Document 11198983

Regulating Electricity and Natural Gas in Peru:
Solutions for a Sustainable Energy Sector
Alex Cade Breekel
B.S. Mechanical Engineering
University of Texas at Austin, 2011
MAY 2 9 2014
Submitted to the Engineering Systems Division in partial fulfillment of the requirements for the degree of
Master of Science in Technology and Policy
at the
June 2014
© Massachusetts Institute of Technology 2014. All rights reserved.
Signature redacted
A u th or
. .............................
Engineering Systems Division
ur rd
9, 2014
Signature redacted
Certified by....
Ignacik Perez-Arriaga
Visiting Professor of Engineering Systems Division
Signature redacted
C ertified by ...
Thesis Supervisor
Carlos Batile Lopez
Visiting Scholar at the MIT Energy Initiative
A ccepted by .........
Thesis Supervisor
Dava Newman
Professor of Aeronautics and Ast onautics and Engineering Systems
Director of Technology and Policy Program
Regulating Electricity and Natural Gas in Peru: Solutions
for a Sustainable Energy Sector
Alex Cade Breckel
Submitted to the Engineering Systems Division
on May 9, 2014, in partial fulfillment of the
requirements for the degree of
Master of Science in Technology and Policy
Peru is one of the fastest growing countries in Latin America, thanks in part to industry fueled by generous endowments of hydro power capacity and natural gas reserves.
However, investment in electricity generation capacity has not kept pace with the
rapid increase in demand and threatens to stymie future economic growth. A flawed
regulatory environment is to blame, and specific roadblocks to increased generation
investments include a dysfunctional capacity payment system, low administratively
determined gas prices, and structural barriers to investment in hydro.
This thesis provides an overview of the design, functioning and historical context
for energy regulation in Peru; identifies the key barriers to generation investment;
analyzes two potential regulatory reforms; and recommends the specific reform that
has the most promise for reigniting investment in hydro.
Two reforms strike at the root of the current problem: The first, increasing the
price of natural gas for power generators up to the economic netback value of LNG
exports, would make hydro a viable investment but would hit consumers with very
large increases in their electricity bills. An alternative approach, a reform to the
capacity payment mechanism, could provide the same benefits in terms of drawing
new generator investment but at a much lower cost to consumers. It would also offer
benefits for regulatory discretion in the future evolution of the grid.
Thesis Supervisor: Ignacio Perez-Arriaga
Title: Visiting Professor of Engineering Systems Division
Thesis Supervisor: Carlos Batlle Lopez
Title: Visiting Scholar at the MIT Energy Initiative
Many people made meaningful positive impacts on me during my time at MIT, both
professionally and personally. In particular, I would like to acknowledge the contribution the following individuals made towards completion of my degree:
Carlos Batlle, for offering regulatory insight throughout the thesis writing process
and connecting my interest to a relevant and timely topic.
Ignacio Perez-Arriaga, for instilling in me a passion for energy policy and regulation
and the fundamentals for analysis thereof.
Melanie Kenderdine, for providing the opportunity to work on the MIT Energy Initiative Symposium, through which I learned the fundamentals of stakeholder involvement
for addressing relevant and timely energy policy issues.
I would also like to thank all of my gracious hosts during my time in Lima. The
learning opportunity was immensely beneficial for completion of the thesis and for
understanding how regulation works in the real world. Furthermore their thoughtful
time spent explaining the nuances of Peruvian regulation and policy will not be
forgotten and I hope to one day return the favor.
Evolution of the Peruvian Electricity Sector
Liberalization of the Electricity Sector: The Electrical Concession Law
Organization of the Market
. . . . . . . . . . . . . . . . . . .
B usbar Tariffs . . . . . . . . . . . . . . . . . . . . . . . . . . .
The Capacity Payment Mechanism
. . . . . . . . . . . . . . .
The Advent of Natural Gas
. . . . . . . . . . . . . . . . . . .
Electricity Sector Troubles: Energy Consumed Out of Contract
Elect ricity Sector Reform: Law to Ensure the Efficient Development
of El ectricity G eneration . . . . . . . . . . . . . . . . . . . . . . . . .
A uctions .. . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Transmission Planning . . . . . . . . . . . . . . . . . . . . . .
Trouble Strikes Again: Energy Shortages of 2008
. . . . . . .
2008 to Present: Ad Hoc Regulation . . . . . . . . . . . . . . . . . . .
The Current Geography of Supply & Demand . . . . . . . . .
Single Node Pricing . . . . . . . . . . . . . . . . . . . . . . . .
C old Reserves . . . . . . . . . . . . . . . . . . . . . . . . . . .
Promotion of Hydro Generation . . . . . . . . . . . . . . . . .
The Southern Energy Node
. . . . . . . . . . . . . . . . . . .
Renewable Energy Promotion . . . . . . . . . . . . . . . . . .
Alternative Regulatory Approaches .
Energy Price Approach . . . . . . . . . . . . . . . . . . . . . . . . . .
Power Price Approach
. . . . . . . . . . . . . . . . . . . . . . . . . .
Hydro Generation Assumptions . . . . . . . . . . . . . . . . . . . . .
Results and Discussion
Energy Price Approach . . . . . . . . . . . . . . . . . . . . . . . . . .
Power Price Approach
Political Costs and Economic Benefits of Higher Gas Prices . .
. . . . . . . . . . . . . . . . . . . . . . . . . .
Design of a Power Payment Reform . . . . . . . . . . . . . . .
A Economic Dispatch Model Formulation
B Hydro Plant Revenue Calculations
C Secondary Market for Pipeline Capacity
List of Figures
Generation Reserve Margin, 2004 - 2014
. . . . . . . . . . . . . . . .
Route of the Camisca Pipeline . . . . . . . . . . . . . . . . . . . . . .
Generation Investment, 1990 - 2012 . . . . . . . . . . . . . . . . . . .
Energy Prices and Energy Consumed Without a Contract, 2004-2012
Transmission Investment, 1990 - 2012 . . . . . . . . . . . . . . . . . .
Generation by Fuel Type and Capacity Margin, 2004 - 2009
. . . . .
Geography of Electricity Supply and Demand
. . . . . . . . . . . . .
Routes of the Camisea Pipeline and Southern Peruvian Pipeline . . .
Generation Supply Curve, 2013
. . . . . . . . . . . . . . . . . . . . .
Generation Supply Curves for Model Scenarios . . . . . . . . . . . . .
Schematic of Supply and Demand for Electricity . . . . . . . . . . . .
List of Tables
Wholesale Gas Prices Around the World . . . . . . . . . . . . . . . .
Cold Reserve Generators . . . . . . . . . . . . . . . . . . . . . . . . .
Hydro Cost Assumptions . . . . . . . . . . . . . . . . . . . . . . . . .
Hydro Availability Factor
. . . . . . . . . . . . . . . . . . . . . . . .
Costs and Revenue Results from Model Scenarios
. . . . . . . . . . .
Hydro Revenue Results from Model Scenarios
. . . . . . . . . . . . .
Chapter 1
Located on the western coast of South America, Peru is the sixth largest economy in
Latin America and is one of the fastest growing. GDP has increased 6% per year over
the last decade while the national poverty rate dropped from 50% to 25% (United
States Central Intelligence Agency, 2014; The World Bank, 2014).
Much of this remarkable growth is the result of recent private sector investment
in extractive industries fueled by abundant domestic energy resources. Peru is the
world's largest exporter of silver and second largest of both copper and zinc, and the
extractive industry accounts for 60% of all exports (Asian-Pacific Economic Cooperation, 2013; United States Central Intelligence Agency, 2014). The success of recent
commercial and industrial activity is in part attributable to Peru's generous endowments of hydro power capacity and natural gas reserves. Future growth prospects
hinge largely on the ability of the government to continue to put those domestic
natural resources to productive use.
Investment in electricity generation capacity has not kept pace with the rapid
increase in demand and threatens to stymie future economic growth. Demand has
grown an average of 7% per year' though generation capacity grew at just 4.9%;
demand is expected to continue to outpace supply for the next several years (Inter'Electricity demand in the United States averaged just 1% growth over the same period.
American Development Bank, 2013). Tremendous new generation investment will be
needed in the medium to long term so that installed capacity can catch up with and
sustain rapid demand growth. Creating the right environment for investment rests
on prudent policy and regulation of the electricity and gas sectors in Peru.
A brief look at the evolution of the reserve margin in Peru - the amount of
generation capacity in excess of what is needed to just meet demand - gives the
sense that there are currently several shortcomings in the regulatory system that
are leading to inadequate levels of investment (Figure 1-1).
Reserve margins are
important to ensure adequacy of supply; if there is ever an acute system failure,
like the unexpected loss of a transmission line, failure of a large power plant, or a
particularly dry hydrological season, system operators can rely on reserve capacity to
ensure that the lights remain on and factories continue producing. The target reserve
margin in Peru for 2013 to 2016 is 33.3% (COES, 2013). This goal has only been
reached less than half of time over the last decade.
Figure 1-1: Generation reserve margin in Peru, 2004 - 2014. The target reserve margin
is 33.3% (COES, 2013).
Reserve Margin
Margin: 33%
The cause of this decline in reserve margin is due to a confluence of regulations that have undermined the government's stated electricity sector objectives. A
dysfunctional capacity payment system, low administratively determined gas prices
and structural barriers to investment in hydro are among the specific roadblocks to
market-driven expansion of generation capacity. Recently, reactionary and ad hoc
regulations in the face of a falling reserve margin have eroded investor confidence and
further strained the ability of markets to ensure efficient investment in the Peruvian
electricity sector.
In the following pages the historical context, design, and functioning of the electricity and natural gas systems in Peru are discussed, along with a detailed nature of
the functioning of the regulatory scheme, some of the past sector challenges and solutions. Following, two regulatory reforms are considered that may move the electricity
sector back towards a sustainable development path.
Chapter 2
Evolution of the Peruvian
Electricity Sector
Prior to 1992, the Peruvian electricity sector was operated as several state-owned
vertically integrated utilities that bundled generation, transmission and distribution
This era was marked by low investment rates in energy infrastructure,
largely due to the absence of cost-based tariffs. Frequent power cuts, high levels
of distribution loss and poor management practices were commonplace (The World
Bank, 2010a). A power crisis in the 1990s revealed just how inadequate infrastructure
investment was at the time: supply met a mere 74% of the total demand and losses in
the distribution system were in excess of 20%, while less than half of the population
had access to electricity (Putnam Hayes and Bartlett Inc and Mercados Energeticos
S.A., 2011).
At about this time, governments across Latin America were considering significant
economic reforms and a new way to regulate their power sectors. Electricity market
liberalization, it was hoped, would increase efficiency, reduce State intervention, and
ultimately attract new sources of funding to maintain and expand national power
systems to sustain rapidly growing economies (Batlle et al., 2010). Largely informed
by the liberalized market design implemented in Chile in 1982, Peru was one of the
earliest adopters in Latin America, kicking off sector reforms in 1991.
Liberalization of the Electricity Sector: The
Electrical Concession Law
A market-based scheme for operation and investment in the Peruvian electricity sector was formally adopted in 1992 under Law No. 25844, the Electrical Concession
Law (LCE)1 , which unbundled the market into generation, transmission and distribution functions; established market mechanisms for wholesale electricity transactions;
established a pricing scheme for regulated electricity transactions; and opened the
transmission network to free access by generators and large power users. The goals
of this reform were to introduce competitive market forces to the development of the
sector and relegate the State to a primarily regulatory role. In the spirit of free markets, a considerable portion of the State's electricity sector assets were transferred to
private hands through the late nineties (The World Bank, 2010a).
The LCE established COES 2 , the electricity system operator, and Osinergmin ,
the regulatory agency that sets gas and electricity tariffs and enforces compliance
with energy, hydrocarbon and mining regulations.
The LCE constrained the role of the Ministry of Energy and Mines (Minem)4 which formulates energy policy, grants concessions and approves regulations for the
energy sector - to referential planning, relegating most future investment decisions
1 Ley
de Concesiones Electricas
The Committee for the Economic Operation of the System, Comiti de Operacion Economica
del Sistema, is a private non-profit committee charged with operating the electricity system based
on merit order generator dispatch. The committee was originally composed of generators and transmission companies, but now includes distribution companies and large free users.
Under the LCE, The Energy Tariff Commission was placed in charge of economic supervision of
the sector. Later, an agency called Osinerg was created in 1997 to absorb some sector supervisory
and oversight roles of the Ministry of Energy. In 2000, Osinerg and CTE were combined. The
combined agency eventually expanded their role into the mining sector and the name was finally
changed to Osinergmin (Organismo Supervisor de la Inversion en Energia y Minas) in 2007 (The
World Bank, 2010a).
'Ministerio de Energia y Minas
to the private sector (The World Bank, 2010a).
Organization of the Market
The reforms included in the LCE restructured the electricity sector of Peru based on
several key principles:
1. Vertical and horizontal unbundling: Generation, transmission and distribution
functions were unbundled, where distributors also serve the function of retailers
2. Least cost economic dispatch: COES manages dispatch of generation and the
operation of the electricity system based on a stochastic hydrothermal economic
dispatch model based on myriad assumptions of future demand, fuel prices, hydrological conditions, etc. The thermal generating units' operation costs are
audited by Osinergmin. The economic dispatch for the entire system occurs on
a least cost basis, independent of contractual obligations. Generators contract
bilaterally with distributors and large free users 6 , and imbalances between generators' actual production with contractual obligations are bought and sold on
the spot market at marginal cost 7 . COES manages the balance of payments
among the generation companies.
3. Administratively determined "busbar" tariffs: Electricity prices for regulated
consumers, called the busbar tariff, are determined as an administratively calculated two-part tariff for energy and power.
5 The market concentration rules were established in 1997 by Law No. 26876, The Antitrust and
Anti-Oligopoly Law of the Electricity Sector, and are enforced by INDECOPI, the Peruvian antitrust
market monitor. Antitrust regulations require regulatory intervention when horizontal concentration
exceeds 15% of the market or vertical concentration exceeds 5%(The World Bank, 2010a).
Consumers with demand over 2.5 MW are classified as large free users and negotiate directly
with generators for power and energy. Consumers with demands greater than 200 kW but less
than 2.5 MW are called small free users and have the option to purchase power from distributors
at freely negotiated prices, from distributors at regulated busbar tariffs or to freely negotiate rates
with generators.
The marginal cost is defined as the variable cost of the last unit of power needed at any given
4. Capacity payments: Peru introduced a capacity payment scheme similar to the
mechanism first introduced in Chile which remunerates generators at administratively determined prices based on their ability to provide power to cover
peak demand. The power component of the busbar tariff serves as the basis of
the capacity payment mechanism.
5. Monopoly regulation of transmission and distribution: Transmission assets are
privately owned and receive regulated return on investment, while both public
and private companies own distribution companies. All consumers pay regulated transmission and distribution rates.
The intricacies of the busbar tariff and capacity payment regulations warrant
further elaboration because of their immense impact on the behavior of market participants.
Busbar Tariffs
The use of an administratively determined electricity tariff was designed to mitigate
market power in the concentrated and weakly unbundled early Peruvian electricity
Set annually by Osinergmin, the busbar tariff was the maximum price at
which distributors were allowed to sell their electricity to regulated consumers and to
contract for supply with generators to serve those consumers.
The tariff consists of two components: energy and power. The energy portion is
determined taking the hourly marginal costs calculated by COES. The price of power,
the basis of the capacity payment mechanism, is set as the annualized fixed cost and
O&M of the hypothetical least cost generating unit able to cover peak demand.
The Capacity Payment Mechanism
Electricity prices based on short-term marginal costs of production can rise only as
high as the value of lost load, an administratively determined figure that is a rough
approximation of the forgone value of consumption. During times where demand
exceeds generation capacity, some load would be shed and the effective marginal
prices of energy would be the value of lost load.
Absent some power payment mechanism, peaker plants needed to cover the final
unit of demand require that the price of energy rise to the value of lost load - while
load is being shed in the system - for enough time for the generator to recover their
fixed costs. The regulator has a design decision to make. In an energy-only system
a tradeoff exists between amount of time blackouts occur and the value of lost load:
the higher the energy price climbs during periods of unmet demand, the less time
is needed to fully remunerate peak generators for their fixed costs. However, many
regulators prefer to avoid both rolling blackouts and volatile prices. A payment that
remunerates peaking generators for some part of their fixed costs provides additional
remuneration that there are fewer hours of unmet demand and lower value of lost
load to be fully remunerated on an annualized basis (Perez-Arriaga and Meseguer,
In Peru, the implementation of the capacity payment mechanism devised can be
conceptually divided into two distinct steps: the process of collecting the money used
for capacity payments and the process of disbursements.
The money designated for capacity payments is paid by regulated consumers as
the base price of power that constitutes one portion of the regulated busbar tariff.
Distributors pay on behalf of consumers for the total capacity of the supply contracts
that they purchase to cover future demand.
The collected money is then distributed to generators by COES on the basis of a
generator's contribution to meeting peak demand. However, only those generators,
sorted from low to high variable cost, that are just needed to meet expected peak load
plus the target reserve margin are awarded the capacity payment. Though generators
that fall above the cutoff are free to contract their power to distributors, the base
price of power portion of the busbar tariff that the distributors pay for the contract
is not guaranteed to go to that specific generator.
There are several aspects of the capacity payment that limit its usefulness as a
tool to encourage adequate investment in generation capacity to reach the target
reserve margin. Specifically, generators face a capacity payment that is too low and
too uncertain to rely on as a necessary component of their returns.
The inadequate size of the capacity payment is due to several strong assumptions
that the regulator makes when calculating the payment, specifically assumptions (1)
that they can predict the particular type of plant best suited as a peaking plant in
Peru and (2) that the costs found in international references for that plant accurately
reflect the cost of an investment made in Peru. Though the theoretical basis of pricing
the capacity payment based on a peaking unit is sound, this method does not account
for the reality of constantly evolving market conditions that would cause reality to
deviate from expectation.
Uncertainty manifests in the size and duration of capacity payments that investors
can expect to earn. Uncertainty of the size of payments stems from the fact that the
payment levels arc updated yearly using newly published prices and disbursements
can change as the level of generation capacity on the system and the required margin
Uncertainty in duration of payments comes from the fact that there is little guarantee that a generator will even be eligible for the capacity payment year to year.
The payment is only granted to generators that, sorted from lowest to highest variable cost, cumulatively just meet expected demand plus the required reserve margin.
That means that the high variable cost generators, those most crucial for providing
supply when demand is the highest, are the least likely to receive the payment and
so have diminished incentives to stay in the market.
The Advent of Natural Gas
In the early 1980s, when Royal Dutch Shell first discovered vast deposits of natural
gas in jungles of Camisea, the government of Peru was unable to finalize an agreement
that allowed the company to continue explore and produce the gas fields. A renewed
interest in a domestic energy supply emerged in the late 1990s as international oil
prices began to rise. After another attempt to reach an agreement with Shell' broke
down 1998, the government finally signed a concession contract in 2000 with a consortium led by Argentina's Pluspetrol to explore and produce the largest portion of
the fields, Block 88.
At around 10 trillion cubic feet (Tcf), Block 88 is by far the largest natural gas
deposit in Peru. The same consortium won a contract for development of neighboring
Block 56, devoting its 3 Tcf of gas to LNG export from the outset (Reinstein et al.,
2010). Had the currently known reserves supplied only the domestic market, the gas
was expected to last 35 years; factoring in LNG exports reduces this estimate to 20
years (The World Bank, 2010a). Over the course of the two 40 year contracts for
Blocks 88 and 56, Peru is estimated to receive $1.9 billion in taxes and $3.5 billion in
royalties (Reinstein et al., 2010).
Gas from Block 88 is transported through the Camisea Pipeline that brings the
gas from the East Peru to the central part of the country near Lima (Figure 2-1).
Favorable transportation tariffs were made possible in the first years of pipeline operation through the Garantade la Red Principal (GRP), a financing scheme designed
to keep transportation tariffs low for early pipeline customers and to guarantee revenues for Transportadora de Gas del Peru (TGP), the concessionaire for the Camisea
The GRP scheme 9 computed a per-unit-shipped transportation tariff by dividing
the total annualized cost of the pipeline by its total capacity, calculated as if the
This time partnered with Mobil.
'The details of the GRP program are laid out in Law No. 27133, Law for the Promotion of the
Development of the Natural Gas Industry (1999).
Figure 2-1: Route of the Camisea Pipeline.
Camisea Gas
pipeline was fully subscribed. Each customer paid this common price for each unit
of gas that they shipped, and the remaining operations and debt financing costs
were socialized to consumers in a surcharge added to electricity transmission tolls.
This scheme remained in place until the pipeline was fully subscribed just four years
after commencement, at which point the shipping tariffs remained unchanged but
the electricity surcharge was eliminated (Reinstein et al., 2010). Prices for pipeline
transportation into the Lima area are at about $1 per million British Thermal Units
(mmBtu) for power generators (Osinergmin, 2014).
Natural gas prices for Block 88 were set through negotiation between the government and producer. Prices are not linked to international prices and the concession
contract stipulates the evolution of future prices based on a basket of liquid fuels.
The prices for gas from other blocks are not stipulated in the concession contracts
and producers are free to charge any price they wish (Reinstein et al., 2010). Prices
for Camisea gas as of January 2014 have floated to about $1.83/mmBtu, among the
lowest gas prices in the region (Table 2.1).
Table 2.1: Wholesale gas prices in 2012 compared to price for Camisea gas (International Gas Union, 2013; Osinergmin, 2014).
Peru (2014)
Electricity Sector Troubles: Energy Consumed Out of
The framework established by the LCE had several underlying structural deficiencies that only became apparent several years after reform. The flaws in the capacity
payment mechanism and reliance on the regulated busbar tariff had led to an unsus10
tainable level of generation investment (Figure 2-2). The resulting reduction in the
reserve margin, rising global prices of oil and a particularly dry period due to the
El Nifio weather phenomenon caused marginal electricity prices to climb starting in
2004 (The World Bank, 2010a). Osinergmin's models failed to reflect these rapidly
rising costs, and the busbar tariff remained essentially unchanged (Figure 2-3).
Figure 2-2: Evolution of investments in generation in Peru, 1990 - 2012 (Minem,
Investment ($Million)
1()Though there was a small surge of investment in the late nineties, investment in much needed
generation capacity in Peru didn't materialize. It is worth noting that only generators with the very
lowest capital costs - inefficient, unreliable and dirty oil and diesel generators - likely constituted
this momentary influx of investment (Putnam Hayes and Bartlett Inc. and Mercados Energeticos
S.A., 1998).
The decoupling of the average marginal prices and the busbar tariff led to a total
breakdown in the normal contractual framework established by the LCE. Distributors
who were legally required to purchase all of their energy needs through long term
contracts but whose income from selling energy was capped by the busbar tariff
could not afford to purchase energy at a price higher than they were legally allowed
to recover. Instead, distributors simply continued to supply their customers electricity
without the commensurate supply contracts. Around this time there was a strong
correlation between the spot price and the amount of energy that was consumed
without a contract (Figure 2-3).
Figure 2-3: Spot price, busbar tariff and energy consumed without a contract in Peru,
Price (US$/kWh)
Energy Consumed Without Contract
Energy Consumed (GWh)
- -Spot
- -Busbar Tariff
2005 2006 2007 2008 2009 2010
2011 2012
The breakdown of contractual trust that resulted from inadequate generation investment and reliance on the busbar tariff scheme was a major failing of the regulatory
system. As distributors continued to eschew reliance on bilateral contracts, generators were left with an uncertain revenue future and even further reduced incentives
to invest in more capacity. In response the energy ministry proposed a reformed regulatory paradigm. The issue of capacity payments was left unaddressed, but the new
regulations significantly changed the way distributors contract for electricity supply
and how costs of those contracts are reflected in regulated tariffs.
Electricity Sector Reform: Law to Ensure the
Efficient Development
of Electricity Genera-
Minem, hoping to improve the investment climate for generation companies and bring
much needed generation capacity into the market, proposed a revised regulatory
framework in 2006: Law No. 28832 - the Law to Ensure the Efficient Development of
Electricity Generation" (Putnam Hayes and Bartlett Inc and Mercados Energeticos
S.A., 2011). The new law introduced an auction mechanism for distributors to contract for a portion of their future demand; changed the way prices for regulated
consumers are determined; changed several aspects of the transmission system; and
introduced distribution companies and large free users onto the management board
of COES (Gacon, 2013).
Though changes to the way the busbar tariff is calculated were certainly needed,
this reform attacked the symptoms (divergence of short-term marginal costs and busbar tariffs) instead of the causes (flawed capacity payment scheme) of the electricity
sector problems.
The government, recognizing the need to allow electricity prices to better reflect the
true costs of generation, devised an auction mechanism for distributors to contract for
their energy and power needs. Cautious of the incumbent companies' ability to exert
market power over the captured customers they serve due to weak unbundling between
generation companies and regulated distributors, the new contracting framework was
designed to be transparent but it is still characterized by close regulatory oversight.
Distributors are responsible for initiating auctions to contract for the full demand
" Ley para Asegurar el Desarrollo Eficiente de la Generaci6n E16ctrica
of regulated consumers at least three years in advance of the contract commencement
dates, and the duration of the contracts must be at least five years. Distributors
and free users can combine their future demands and participate in joint auctions
to encourage economies of scale (Putnam Hayes and Bartlett Inc and Mercados Energeticos S.A., 2011). In this way the objective of the auctions is two-folded: first,
from the tariff design point of view, it is expected that the pressure of potential new
entrants on incumbents could drive prices towards what would exist in a fully competitive market; second, the auctions are expected to serve as a tool to reduce the
entry barriers for these new entrants, through the provision of long-term contracts
and sufficient lead times to allow for the construction of the new plants.
Osinergmin establishes a hidden price cap for energy that generators offer in the
auctions based on power demand models. The cap is kept secret unless a distributor
is unable to fulfill its entire request without exceeding the cap. If the cap is exceeded
a new auction round is called and is open to any generators who wish to participate.
The price that generators bid is only for energy, and generators are remunerated
at their bid price (pay-as-bid). Determination and payment of the price of power
remains as it was before (Putnam Hayes and Bartlett Inc and Mercados Energeticos
S.A., 2011).
The auction mechanism does not replace administratively set regulated rates, but
is rather a supplemental way of contracting for supply. Distributors are free to choose
to contract for supply bilaterally at or below the busbar tariff, or through the auction
mechanism (Putnam Hayes and Bartlett Inc and Mercados Energeticos S.A., 2011).
Electricity prices for regulated consumers are a weighted average of the auction prices
and the busbar tariff set through modeling as before (Cangalaya, 2013).
Though the auction mechanism had significant advantages in how busbar tariffs
arc determined, it was ultimately designed to encourage adoption of newly available
natural gas in the power sector. Investment in hydro generation, which up to 2006
had represented the lion's share of capacity and generation in Peru, was severely
limited due to contract timing and scale of the auction contracts.
The three year lag between when the contracts are signed until the contractual
obligations begin is simply too short for large scale hydro power investments. Additionally the five year contract duration does not ensure a sustained cash flow for a
period long enough to mitigate significant capital risk.
The scale of the auctions is too small to capture the benefits that economies of
scale can provide for large projects. Currently, any individual distributor can request
an auction to be held to meet their demand. The regulations also allow distributors
to call simultaneous auctions to encourage economies of scale in generation, but there
are no requirements to do so. A large hydro or thermal plant would need to contract
a significant portion of their capacity to garner financing.
Low natural gas prices have helped diversify Peru's energy mix, decrease its reliance on imported oil and provide domestic industries with seemingly low cost energy.
However, the success of low gas prices was at the cost of investment in hydro power.
The share of natural gas as a fuel for generation from 6% in 2003 to over 30% in
2008, completely inundating the new pipeline by 2008, just four years after it was
first put into service. This quick adoption of low priced natural gas lowered the average spot price and made it even harder for new generation in other technologies to
be financially viable.
Transmission Planning
Prior to the electricity sector reform there was no formal role for the State in planning transmission investments. New lines were built in response to market demand
and remuneration to transmission owners fluctuated yearly based on the concept of
an Adapted Economic System. The lack of market demand to spur investments and
uncertain yearly revenues for investors led to chronically low investment rates in transmission assets in the years following sector liberalization (Figure 2-4). Responding
to the failure of the regulatory regime to garner adequate transmission investments,
- the private investment promotion agency - tendered several projects
under Build, Operate, Own and Transfer (BOOT) contracts between 2000 and 2002
(Ruiz and Rosell6n, 2012).
Figure 2-4: Evolution of transmission investment in Peru, 1990 - 2012 (Minem, 2012).
Investment ($Million)
500 400
In an attempt to rectify the conditions that led to such low levels of transmission investment in the years since the LCE, Law No. 28832 established a mandatory
transmission planning responsibility for COES and a system of guaranteed future revenues for asset investors (The World Bank, 2010a). Once per year COES publishes a
transmission system diagnostic report that details transmission network issues such
as congestion or voltage problems. Private agents and stakeholders submit proposed
transmission additions to COES, who assembles these proposals into a four year transmission expansion plan. After approval from Osinergmin and Minem, Proinversi6n
holds public auctions for concession contracts where transmission investors offer their
lowest monthly payment needed to invest. Electricity consumers pay postage stamp
tariffs that remunerate the winners of such auctions based on total energy consumption.
Trouble Strikes Again: Energy Shortages of 2008
During two consecutive days in drought stricken August of 2008 the main electricity
system in Peru suffered from a shortage of generation that led to significant power
The Agency for the Promotion of Private Investment (Agencia de Promoci6n de la Inversi6n
Privada - Proinversi6n), which was created to foster private participation in strategic infrastructure
investment. At the time of the tenders the agency existed under a different name but for purposes
of this discussion was functionally the same.
cuts. The 2006 reforms had come too late to stem the tides of the sustained period
of underinvestment in generation capacity and transmission lines that preceded the
sector restructuring (Figure 2-5).
The subsequent lack in generation investment,
combined with acute constraints in the Camisea gas pipeline and power transmission
lines, left the system in dire straits (The World Bank, 2010a).
Figure 2-5: Total generation by fuel type in Peru and capacity margin, 2004 to 2009.
Note that the target capacity margin in Peru is 33.3%.
Generation (GWh)
Reserve Margin
Natural Gas
wCoal -Reserve
The Camisea pipeline operator was only required to expand capacity of the pipeline
commensurate with the amount of firm capacity contracts that were signed by customers. Early in the life of the pipeline some generators were reluctant to sign these
contracts despite relying on the pipeline to fuel their power plants. The pipeline had
enough capacity to serve those customers with and without firm capacity on most
days, but not during the particularly high demand days in August, thus leaving some
generation capacity unable to contribute to meeting peak demand (The World Bank,
The shortage of generation capacity and strained transmission lines led to extremely high spot prices and divergence of prices between different regions of Peru.
High and geographically disparate prices along with acute shortage events brought
the health of the electricity sector to the forefront of the political agenda. Scrambling
to find a quick fix to the highly visible problems in the sector the government enacted
several minor sector reforms in quick succession.
2008 to Present: Ad Hoc Regulation
Much has changed since the 2008 power shortages. However, unlike previous iterations
of sector reform, the most recent changes have largely been reactionary and without
a coherent guiding framework. A series of quick reforms in 2008 were largely meant
to be temporary fixes, but the lack of sustainable solutions have left many of the
changes in place today with no clear picture of what comes next.
The Current Geography of Supply & Demand
In 2013 demand in Peru peaked at 5.6 GW, and installed generation of 7.3 GW
comprises roughly 45% natural gas, 45% hydro, 10% oil, 1% coal and less than 1%
renewable (COES, 2014). The electricity system is radial, with a central zone that
has the majority of supply and demand, connected to northern and southern zones
transmission lines. The geographic distribution of capacity, demand and generation
are displayed graphically in Figure 2-6.
Figure 2-6: Geography of electricity supply and demand in Peru (Osinergmin, 2012).
The value in the arrows are the total electrical energy that is exported from the center
of the country to meet demand in the north and south in 2013.
Demand: 15%
Capacity: 12%
Generation: 9%
Demand: 65%
Capacity: 76%
Generation: 82%
Demand: 20%
Capacity: 12%
seneration: 9%
The concentration of generation in the center of the country is largely a result of
investment in gas generation that relies on the inexpensive Camisea Gas (Table 2.1),
which powered 37% of total electricity generated in 2013. As a result, the power lines
extending to the north and south of the country are congested about 40% of the year,
transmitting 17% of the total energy generated in the country out of the central zone
and into the northern and southern regions (Barco, 2012).
Single Node Pricing
Emergency Decree 049-2008 changed the way electricity prices are set and generators
are remunerated in order to make wholesale prices lower and uniform across the
country. Instead of relying on the locational marginal prices that determine unique
costs at each busbar on the system, COES now calculates the marginal price of
electricity for the entire country using a single-node model that ignores electricity and
gas transmission constraints. Generators that are dispatched for security of supply
but cost more than the single node marginal price are paid the difference between
their actual costs and the idealized marginal price.
Using a single node price lowers average wholesale prices in security constrained
locations and dulls incentives for efficient generation investment. Locational marginal
prices are efficient at sending locational signals because in places where a very expensive generator is needed to produce electricity during peak demand, prevailing high
electricity prices encouraged new and more efficient generators to invest in these areas, thereby lowering the cost of electricity in the long term. Transitioning towards a
single price eliminates these locational signals and discourages generation investment
in the areas where it is most needed. Furthermore, generating units that consistently
provide the last few units of power are foregoing the ability to capture economic rents
for their fixed investments, discouraging them from participating in the market in
real time and discouraging new investments in the future.
In addition to the acute problems caused by ignoring transmission constraints in
pricing electricity in the wholesale market, the problem of regulatory risk looms large.
Emergency Decree 049-2008 was put in force in 2008 with the intended expiration
of 2011.
Subsequent decrees extended the date first to 2013 and again to 2016.
This constantly shifting goal post further steers risk averse investors away from the
Peruvian market (EDEGEL S.A.A., 2014).
Cold Reserves
Due to a chronic lack of investment in new generation capacity under the normal
capacity payment scheme, a new strategic reserve mechanism was devised to ensure
that there was sufficient generation capacity to meet peak demand in emergency situations. Cold reserves are procured outside of the capacity payment scheme established
under the LCE. Generators that are procured through this mechanism are meant to
only run in times of system emergency (Tudela and Paredes, 2013).
A series of government decrees, culminating in Urgent Decree No.
established the role of Proinversi6n to hold a reverse bid auctions for predetermined
capacities in specific locations in the country. Only new generators are eligible to
participate in the auctions and must have a certain amount of on-site fuel storage
capability. The generators awarded cold reserve status consistently garner payments
for power in excess of the standard capacity payment (Table 2.2).
Table 2.2: Basic information regarding cold reserve generators.
Note that normal
payment for power is 6,190 US$/MW-month in 2013 (Osinergmin, 2010; Cangalaya,
Puerto Maldonado
Power Price
($ Million)
June 2013
July 2013
Feb 2015
Feb 2015
June 2015
Promotion of Hydro Generation
Development of hydro resources is once again of major interest to the government
of Peru.
Three of the nine guiding principles for the development of the energy
and three of the seven electricity sector goals" directly or indirectly mention
an increased reliance on hydro power in the country.
Estimates of the hydrological resource base in Peru are enormous. The technical
potential is a staggering 60 GW, nearly ten times the entire installed capacity in 2013
(The World Bank, 2010b). However, due to many institutional and financial barriers
hydro development has come to a near complete halt in recent years. Total generation
from hydro dropped from 85% of total in 2003 to just 54% in 2013, with reliance on
natural gas increasing at a rate of over 30% year on year (COES, 2014).
In an attempt to overcome some of the structural barriers to hydro development
inherent in the auction mechanism and low natural gas prices, new rules15 were introduced in 2008 that discounted all hydro bids for the supply auctions by an amount
of the regulator's choosing, so far 15% (The World Bank, 2010b). If the hydro developer wins the auction at their discounted bid, they are guaranteed to be remunerated
at their actual bid price (Putnam Hayes and Bartlett Inc and Mercados Energeticos
S.A., 2011). Yet another 2008 change' 6 applied accelerated depreciation to the capital cost of new investments hydro, and the maximum duration of auction contracts
was extended from 10 to 20 years (Batlle et al., 2012). Even with these 2008 changes
there has been very little recent hydro investment in the country (Putnam Hayes and
Bartlett Inc and Mercados Energeticos S.A., 2011).
Following these 2008 changes to the auction mechanism introduced by Law No.
28832, Proinversi6n conducted two auctions exclusively for hydro technologies. Auctions in 2009 and 2010 secured slightly over 650 MW of hydro capacity investment.
To develop a diversified energy matrix focused on renewable sources and energy efficiency; To
develop a self-sufficient infrastructure for energy production; To develop an energy sector with a
minimum environmental impact and low carbon emissions as part of sustainable development (Tafur
et al., 2012).
14 Promote projects and investments to achieve a diversified energy matrix based on conventional
and non-conventional renewable, hydrocarbon, geothermal and nuclear energies that ensure power
supply in the country; Prioritize construction of efficient hydro power plants for national electricity
generation; Promote an intensive and efficient use of conventional and non-conventional renewable
energies as well as distributed generation (Tafur et al., 2012).
15 Legislative Decree 1041
Legislative Decree 1058
Though the auctions were successful in garnering investment in hydro generation capacity, there was uncertainty regarding who would ultimately bear the cost of the
projects procured by the state outside of the formal distributor supply auctions. In
the end the contracts were shouldered by Electroperu, the state owned electricity
The Southern Energy Node
Passed in late 2012, Law No. 29970 - designed to strengthen energy security by
diversifying electricity sources, reduce dependence on imported fuels and increase
reliability of the natural gas supply chain - gave increased authority and a statutory
mandate to Minem to prioritize projects that increase the reliability of the energy
supply chain in Peru, especially to the south.
The demands for gas from the Camisea gas pipeline far exceeded expectations, and
had reached the full capacity of the line by 201117. More pipeline infrastructure was
needed to continue to increase reliance on the abundant Camisea gas. The Southern
Peruvian Pipeline, a project that falls within the legal framework of Law No. 29970,
will be a 1,200 km line that will bring Camisea natural gas to the southern part of
the country to serve industrial and power sector consumers, with the long term goal
of establishing "The Southern Energy Node" and creating a petrochemical industry
based in that region (Figure 2-7).
Originally planned as a private construction project that was delayed by several
financial and technical problems, the government now plans on offering a concession
for the pipeline that includes guaranteed income over the life of the contract, using
a financing scheme similar to the GRP. The selection process for the concessionaire
is now underway with plans on finalizing the deal, after four consecutive delays in a
year and a half, in late June 2014. The total cost is estimated to be $2.5 billion, it
Though, as discussed before, there were acute pipeline constraints in 2008, these constraints
occurred before the pipeline was operating at maximum throughput capacity as it is now
Figure 2-7: Routes of the current Camisea Pipeline and the proposed Southern Peruvian Pipeline.
Camisea Gas
Southern Peruvian
will be the largest project ever undertaken in Peru (No Author, 2014b).
Proinversi6n, in order to create an anchor demand for the pipeline and to quickly
provide electricity generation assets in the south of the country, held a concession
auction for two 500 MW power plants, one in Ilo and the other in Mollendo 8 . Both
plants will have a simple cycle diesel turbine generators. When the pipeline arrives,
both generators will convert to gas fired combined cycle and will have a combined
output of 1,500 MW (No Author, 2014a).
Another anchor demand project promoted by the government is a smaller dieselthen-gas 200 MW power plant located in Quillabamba, south of Camisea but much
closer to the fields than the Ilo and Mollendo plants (Electroperu, 2013).
of again relying on Proinversi6n, this time the government required Electoperu, the
state owned electricity generation company, to invest in the power plant as the sole
owner 19
In an effort to encourage a market-driven decentralization of power production
The Mollendo plant was awarded $5,899 /MW-month and is set to start up on a May 2016,
and the Ilo plant was awarded 5,750 /MW-month and will start generating in March of 2017 (No
Author, 2014a).
Set to be completed in 2016, this 200 MW open cycle turbine will cost around $150 million
(Electroperu, 2013).
in the country, Law No. 29970 subsidizes the cost of Camisea gas from Field 88 for
generators in the north and south of the country so that all generators will pay the
same price per unit of delivered natural gas. The cost of this mechanism is funded
through electricity consumers by a transmission toll.
Renewable Energy Promotion
The primary mechanism for promoting investment in renewable energy in Peru is
technology-specific auctions, governed by Legislative Decree 100220. Every two years
Minem determines the need to call an auction for renewable generation, specifying
the desired amount of energy for each type of generation technology 21
The auction process for renewable energy proceeds much like the conventional
supply auctions. Investors offer price-quantity pairs, declaring the total amount of
energy they expect to generate over a year in MWh and the price that they require
for that generation in $/MWh (Gacon, 2012).
Osinergmin calculates a price cap and awards are made to all generators that
comprise the portfolio of generation assets that meets the technology quotas of the
ministry at the least cost. Renewable energy generators that win the auction sell
energy to the national grid at system marginal costs. Periodic financial settlements
occur whereby the government can offer additional remuneration to the generator if
their market earnings fall short of their bid, or where the government can impose
penalties on a generator that produces less energy than offered in its bid (Gacon,
Published in May of 2008.
Generation technologies that are eligible for the renewable technology auctions are wind, solar,
tidal, biomass, geothermal and hydro under 20 MW. Hydro facilities larger than 20 MW are regulated
as conventional generation technologies.
Alternative Regulatory Approaches
Despite the myriad small regulatory changes instituted since 2008, the electricity system still faces significant underinvestment in generation. The government's response
has been to increasingly rely on frequent and unpredictable involvement of Proinversi6n to bring in new investment. This type of government intervention has been a
messy affair: hydro auctions have been cleared with unidentified buyers; cold reserves
have been solicited with expensive out-of-market procurement; generators serving as
the anchor demands for the southern energy node rely on expensive fuel until low
cost natural gas arrives. These regulatory interventions crowd out efficient generation investment and diminish the impetus for new and comprehensive regulatory
It is imperative that policy makers in Peru address the three fundamental market
flaws moving forward: the dysfunctional capacity payment system, the low administratively determined natural gas prices and structural barriers to investment in
hydro. The following analysis considers the impacts of explicitly addressing each of
the first two fundamental reforms in terms of economics and increased levels of hydro
investment. Because of the nature of the reforms, their impact on the market can
be abstracted to consider the mechanism through which they send efficient market
signals to generators.
Energy prices are determined by the variable costs of generators on the system.
Controlling the price of natural gas, which fuels 45% of the generation capacity in
Peru, would have a direct impact on the average energy prices and therefore an impact
on generator revenues. Allowing the price of natural gas to rise to its economic value
would result in a more efficient allocation of the scarce resource and perhaps to an
increase in hydro capacity investment that is so desperately needed in Peru.
Power prices for generators in the Peruvian market stem directly from the capacity
payment, which currently does not reflect the actual cost of generation investment
and has failed to garner the level of investment sought by Osinergmin. Fundamental
reform of this system of power payments must be considered if the regulator wishes
to increase generation investments without continuing to rely on the costly ad hoc
methods pursued recently, such as the cold reserves and Proinversi6n hydro auctions.
Attempting any structural reform of regulations that improve the efficiency of market signals for generators in Peru must be undoubtedly be coupled with the removal
of the structural barriers to investment in hydro. Specific strategies for pursuing these
reforms and the relative impacts on the market are explored in the following analysis.
Chapter 3
At the root of the problem of generation underinvestment, especially in hydro power,
is that efficient electricity market signals are stymied by flaws in the design of regulations. Because more efficient market signals can come from either energy payment
remuneration - through economically priced natural gas - or from power payment
remuneration, reforms to both sources of generator revenue are explored separately
below. However, generator revenue comprises the sum of energy and power payments,
and in both cases of reform considered here, reform is made on each of these revenue
sources independently, while the functioning of other remains as it is today. Explicit
changes needed to address barriers to hydro investment are addressed in both cases.
Energy Price Approach
The impacts of a change in energy prices in Peru are explored using a simple unit
commitment model, for which a complete description can be found in Appendix A.
For computational efficiency, a simplified mix of generators was used that reflects
the actual supply curve in Peru for December 2013. Both the simplified and actual
supply curves can be seen in Figure 3-1.
Figure 3-1: Actual 2013 and idealized (Base) generation supply curves at current
natural gas prices. The shaded area represents the installed capacity relying on
Camisea natural gas (COES, 2013, 2014).
Variable Cost ($/MWh)
Cumlative Generation Capacty (MW)
The model is run for one scenario that reflects the current prices
the Base
Case - and two scenarios that consider the economic opportunity cost of the fuel:
1) the LNG Case where natural gas is priced at the value of LNG exports and 2)
the Alternative Fuel Case where gas is priced at the highest it could rise before a
generation technology relying on an alternative fuel has an equal variable cost.
A study by The World Bank (2010b) found an economic value of natural gas
by calculating the netback price for exported LNG as a function of international oil
prices1 . They found that, with a barrel of oil at $100, the netback value of natural gas
at the wellhead is approximately $4.6/mmBtu. Adding the Camisea pipeline tariff
brings the LNG-based netback value of natural gas to $5.6/mmBtu at the point of
To estimate the opportunity cost of natural gas as a fuel for the power sector we
can consider the variable cost of generators operating on the next most expensive fuel.
Oil is the second hydrocarbon fuel of choice in Peru, and the least expensive generator
relying on oil has a variable cost of $147/MWh, far more expensive than the highest
variable cost generator relying on Camisea natural gas at $30/MWh. Assuming a
'The economic netback value of a fuel is the potential revenues from sales to a specific market
minus the cost of delivering the gas to that market. In this case it would be the price that a
hypothetical LNG exporter would pay to just break even on sales to the international market.
heat rate of 10 mmBtu/MWh, the price of natural gas that brings the Camiscareliant generator to the same variable cost as the oil generator is $14.7/mmBtu.
The three scenarios will thus be defined as: the Base Case with natural gas at $1.2
- $2.8/mmBtu; the LNG Case with natural gas at $5.6/mmBtu; and the Alternative
Fuel Case with natural gas at $14.7/mmBtu 2 . The impact that these gas prices has
on the generation supply curve can be observed in Figure 3-2.
Figure 3-2: Generation supply curves for Base, LNG and Alternative Fuel Cases.
Variable Cost ($/MWh)
Cumlative Generation Capacty
An alternative method for allowing gas prices paid by generators to reflect the
scarcity value of the natural gas is to allow a secondary market for pipeline capacity
on the Camisea Pipeline, and on any future gas pipelines. In such a market consumers
openly buy and sell capacity contracts that give the holder the right to move gas
through a pipeline. In this way those consumers that value fuel delivery the most
at a given time are willing to reflect that value in a market, presumably leading to
an increase in effective fuel price. As the marginal cost of generation rises to reflect
the cost of generators with higher variable costs than those that rely on Camisea
gas, generators should be willing to pay for gas up to the point where their variable
cost approaches that of the next highest generator. In the likely case where the next
The range of gas prices for the Base Case are an artifact of the generators' reported costs for
fuel. Generators in the Peruvian electricity system that rely on Camisea gas self-report their costs,
which are not audited like all other generation units. This gives generators the opportunity to price
in fixed costs associated with pipeline capacity contracts or bid strategically for other reasons. For
simplicity, this analysis relies on the reported values of natural gas prices.
generator is running on oil, there is a lot of room for prices to rise. Creating such
a market is within the regulatory purview of Osinergmin and would have similar
consequences for energy prices as the Alternative Fuel Case and will not be analyzed
in full here. For a more in-depth discussion of the impact that a secondary market
for pipeline capacity might have on the Peruvian market, see Appendix C.
Power Price Approach
To consider how reforming the current capacity payment mechanism would impact
remuneration for a hydro generator, we must first define the type of power payment
scheme to analyze. The hypothetical concept considered here will be a quantity-based
approach that relies on reverse auctions for defined generation capacities where generators offer the minimum yearly payment they would need to enter the market, and
in the case of greenfield investments the duration of the contracts are commensurate
with the lifetime of a power plant. The power payments that are awarded through
the auction, if we assume that the auctions are fully competitive, will reflect the
supplementary revenue that a generator would require in addition to their expected
energy payment remuneration to enter or remain in the Peruvian electricity market.
This scheme would compliment energy portion of the electricity supply auctions that
currently exist.
The specific details of how best to design this new quantity-based power payment
approach are discussed later. For purposes of the financial analysis we will assume that
the expected energy revenues for a hydro generator are equivalent to the time-average
marginal cost of generation, and that any power payment would simply supplement
energy revenues.
To understand the costs of this new scheme, a simple calculation
is conducted that considers the average marginal cost of electricity, the availability
of the hydro as discussed above, and hydro variable costs. A complete description of
these calculations can be found in Appendix B.
Hydro Generation Assumptions
To study how the alternative regulatory scenarios affect the financial viability of hydro
generators, a better understanding of their financial and operational characteristics is
needed. The question we would like to ask is how high electricity sector remuneration
would need to rise to offer "enough" revenue for new hydro investors. However there is
no simple invariable answer to this question. Physical characteristics such as reservoir
size, estimated inflows and susceptibility to changing hydrological cycles define the
operational - and thus the cost and revenue profile - of any particular hydro generator,
and capital and financing costs change with time and at the whim of international
For this simple analysis, however, a single cost metric is used to evaluate the
various regulatory scenarios and is considered a threshold value rather than the true
cost of investment for all hydro generators in the Peruvian market.
the necessary simplification to the cost profile of hydro generators, we can define
adequate remuneration as the amount of revenue that would cover the annualized
fixed and variable costs of a new hypothetical generator. Table 3.1 contains some
basic information on the cost of hydro investment in Peru.
Table 3.1: Hydro cost assumptions for scenario analysis. All hydro assumptions
except fixed O&M are from The World Bank (2010b). Fixed O&M is from Gacon
(2013). The annualized capital cost was computed considering a thirty year recovery
period and 15% rate of return. All costs are normalized on a per-kW basis.
Variable O&M
Fixed O&M
Overnight Capital Cost
Annualized Capital Cost
Considering the costs in Table 3.1, our particular hypothetical hydro generator
would need a net revenue of at least $304/kW-yr to just break even with a 15% rate
of return. This value will be used as the threshold net income that would encourage
hydro capacity investment. Note that this is strictly financial in nature and that
any structural barriers that remain would still prevent investment, even when the
expected financial returns are high.
Peru has an energy-constrained hydrothermal electricity system: hydro generation
is subject to variable hydrological cycles that places an effective cap on the amount of
energy that can be generated using hydro. For the purpose of the analytic model, the
monthly average capacity factors for hydro over the last ten years are used to adjust
available generation capacity and remuneration for hydro generators in the scenarios
(Table 3.2). Though this is a crude approximation of the availability of hydro through
the hydrological cycle, it will suffice to gain an understanding of the impacts of scaling
the availability of the generator commensurate with reasonable inflow assumptions.
Table 3.2: Hydro availability factor, taken as monthly hydro generation as a fraction
of firm capacity from 2008 to 2013 (COES, 2014). The average availability over this
period is 0.65.
Defining the meaning of firm capacity for the purposes of capacity payment eligibility is a design decision of the regulator. In Peru, the firm capacity of a hydro
generator is defined as the amount of power that they could produce during the lowest
hydrological inflow month for a thirty year duration (The World Bank, 2010b). For
many hydro generators on the system, their firm capacity is commensurate with their
effective capacity, though some are discounted heavily. For this analysis we assume
that firm capacity is equivalent to installed capacity.
Chapter 4
Results and Discussion
The following section discusses the results of the analysis scenarios in terms of costs
to consumers and revenues to generators. More detail regarding the design and implementation of either of these approaches is also discussed here.
Energy Price Approach
Figure 4-1 gives a simplified schematic view of supply and demand curves for electricity. Price is on the vertical axis and quantity is on the horizontal. The supply curve
represents cumulative generation capacity, stacked from low to high variable cost, and
the demand curve is vertical and represents total consumer demand for electricity. It
is represented vertically because consumers have little ability to change their demand
in real time based on prices, so demand is said to be inelastic.
The conditions that define supply and demand change on an hourly basis'. In
every hour, the most expensive generator that is needed to meet demand establishes
the marginal cost, or the cost of supplying one more increment of power for that
'In reality conditions change on an infinitesimal time horizon: the supply curve and precise level
of demand are never exactly the same twice. However, for simplicity this analysis simplifies the time
variance of supply and demand into discreet hourly periods.
Figure 4-1: Schematic of supply and demand for electricity. Consumer costs are the
sum of marginal cost times demand for every hour.
Marginal Cost
Quantity (MW)
Consumers pay - and generators receive - the marginal cost of energy for
each hour for every unit of energy consumed 2 . Below the supply curve is the true
cost of generation that accounts for fuel and O&M. The area between supply curve
and the marginal cost is called generator surplus and goes towards paying the fixed
investments of generators. Any generator surplus in excess of fixed investments are
maintained as profits.
Table 4.1 summarizes total consumer cost and total generator surplus for the
economic dispatch modeling scenarios. The average marginal cost is time-averaged,
meaning that the marginal cost in each our is averaged over time, irrespective of
demand. Note that the time-average marginal cost in 2013 was about $25/MWh,
quite close to the Base Case scenario.
Table 4.1: Consumer costs and generator revenues for the economic dispatch modeling
Alt. Fuel
Gas Price
Avg. Marginal Cost Consumer Cost Generator Surplus
($ million)
($ million)
0 - 2.9
Evaluating the magnitude change in total consumer costs, it is worth noting that
though natural gas prices are a large driver of energy costs, costs to consumers do
Though consumers do not pay in real time, the average marginal cost is an approximation of the
cost of electricity to consumers over the long term because generators internalize their expectations
for average marginal costs in supply contracts.
not rise one-to-one with an increase in gas prices: an 400% increase in the price of
natural gas between the Base and LNG Cases results in a 70% increase in consumer
energy costs 3 . A 1200% increase in gas price increases consumer costs just over 300%.
This fact reveals that natural gas generators are not always the marginal generator,
but rather prices are sometimes set from generators not relying on Camisea natural
Nearly all of the increase in consumer costs for energy is directed towards generator
surplus as opposed to paying for the added cost of the natural gas. This is largely
an artifact of the large hydro capacity on the system, which operates at a nearzero variable cost. For this type of generator, any energy payments that result from
marginal cost pricing is nearly all surplus.
Table 4.2 shows these revenues and generation costs on a per-kW capacity basis
for the hypothetical hydro generator on this system 4 .
Table 4.2: Results from economic dispatch model in terms of hydro generator revenues.
Alt. Fuel
Net Revenue
Gas Price Energy Revenue Power Revenue
($/kW-yr) ($/kW-yr)
0 - 2.9
This analysis shows that under the Base Case scenario hydro is not competitive,
with net revenues falling far short of the $304/kW-yr target calculated above. Bringing gas prices up to the opportunity value of LNG on the world market would just
surpass the revenue requirements while increasing consumer costs and generator surplus 70%. Increasing the price of gas commensurate with its opportunity cost in the
power sector increases net revenues for hydro generation dramatically but increases
consumer costs and generator surplus by over 300%.
Though the price of gas for the base case ranges from 0 - 2.9 $/mmBtu, a capacity-weighted
average of 1.12 $/mmBtu was used for calculating comparisons. The capacity-weighted average was
found by multiplying the price of natural gas times the capacity of the generator, and dividing by
total generation capacity relying on gas.
Note that the power payment for capacity from 2013 was used, 6,190 US$/MW-month.
This analysis shows that increasing the price of natural gas to a value near the
opportunity cost of the fuel for LNG export would be nearly ideal for encouraging
new hydro investment in the system. However, these increases in natural gas prices
result in large associated increases in consumer costs. This is a political challenge
that may prove untenable. Complicating the politics of increasing energy prices is the
fact that many of the generators that would benefit from the increase in surplus are
owned by large multinational corporations. Much of the additional consumer costs
would leave the country as increased corporate profits, a political challenge nearly as
great as increased costs.
Political Costs and Economic Benefits of Higher Gas
If raising costs to consumers is completely untenable, mechanisms can be devised that
transfer the additional revenues that generators might capture back to consumers
through taxes on installed capacity or lowering the capacity payment. However, the
long term efficiency gains that would result from having natural gas reflect market
price are nontrivial.
Another consideration when thinking about the costs to consumers is that the large
increase in marginal cost of energy production reflected in these modeling simulations
would be short term and transitory and would be relieved as more hydro generation
enters the market, providing sustainable low carbon energy generation to meet future
demand while preserving the natural gas endowment to its highest value use. Another
driver for transient reductions in energy prices that are not reflected in the model
is the move to combined cycle power plants that rely on Camisea gas. Combined
cycle power plants are about 30% more efficient than open cycle, and therefore more
economical at a given gas price. To alleviate the price shock to consumers and allow
the system to remain closer to equilibrium through the transition to higher gas price,
a set schedule of price increases should be published ahead of time to allow market
participants to react economically to the new generation cost reality.
Lastly, under this reform scenario, it is imperative that current barriers to hydro
investment - including the lag and duration of energy supply contracts - be addressed
with haste. Without eliminating these barriers, increasing the cost of natural gas in
the power sector will simply increase energy costs, since the market efficiency gains
will only be realized if both the gas prices are brought to their economical value and
hydro investors are allowed to compete on a level playing field.
Power Price Approach
How large would a power payment need to be for our hypothetical hydro generator,
assuming that their energy remuneration is unchanged? Considering the Base Case
model run, a hydro investor, net of operational costs, can expect to earn $142/kWyr from energy payment revenues. Therefore, to meet the $304/kW-yr threshold, a
hydro investor would need an additional $162/kW-yr to be fully remunerated.
To consider the costs to consumers that such a payment would entail, imagine
that hydro investment met the total future capacity needs of Peruvian electricity demand, which has averaged 7% growth per year for the last several years, and that
energy prices remained the same as the average marginal cost from the Base Case .
If all new demand growth for the next decade was met with hydro paid a power
price of $162/kW-yr, the total additional cost to consumers over the current capacity payment would be $140 Million, 80% less expensive to consumers than bringing
natural gas costs up to the LNG Case price for just one year. When the future costs
of the discriminatory power payment are discounted to present value using a 10%
discount rate, consumer savings come to a staggering 90% over the LNG Case gas
price increase.
Peak demand in 2013 was 5,565 MW
Design of a Power Payment Reform
With such a seemingly positive return for this method, what would such a power
payment scheme look like in practice? There is still much debate on what an effective
power payment system should look like in practice but a few guiding principles should
be at the forefront of a reform. One way to operationalize good regulatory principles
is to consider four regulatory decisions that must be addressed adequately under a
new power payment scheme (Rodilla and Batlle, 2013):
1. Identification of counterparties (buyers and sellers)
2. The precise definition of the power product to be sold
3. Determination of the type of mechanism (price or quantity)
4. The design of the process
The Counterparties
Currently, the counterparties for the capacity payment mechanism are regulated users
and generators. Under a new power payment scheme, the buyers should be all users
of the network, both regulated and free, to avoid the implicit cross subsidy that
exists in the current power payments'.
Osinergmin could look at the centralized
Brazilian energy auctions as an example of a centralized auction procedure that encourages economies of scale and assigns the cost of power contracts to all consumers
(Mastropietro et al., 2013; Putnam Hayes and Bartlett Inc and Mercados Energeticos
S.A., 2011). One way to distribute the costs fairly is to add the new security of supply
mechanism to an additional charge to the transmission tariffs that all consumers are
subject to.
The sellers that would participate in the new capacity auctions would be all of
those generators that the regulator saw fit, depending on the regulatory objective.
'The cross subsidy manifests from regulated consumers bearing the entire power payment that
is meant to encourage investment that benefits all consumers, both regulated and free.
Perhaps the first-best option from an economic point of view is to allow all generators to participate in the auctions. Physical realities of market concentration, fuel
price distortions and inherent differences between generation technologies may compel
the regulator to prefer discretionary auctions, choosing between thermal and hydro
generation, or incumbents and new entrants. This would give Osinergmin increased
discretion and control of who enters the market and when, while consumers only bear
additional costs for those generators that are deemed necessary by the regulator.
The Product
The precise definition of the power product is crucial in determining the success of
the power payment scheme. The duration and lag period of the power contracts
that result from the auctions is of critical importance for the promotion of hydro
power generation. Lag times for new generation investment should be longer than
the current supply auction lag to account for the inelasticity of demand for capacity
in the short term inherent with long lead-time generation investments (Rodilla and
Batlle, 2013).
A distinction between new investments and incumbents may also be warranted.
Greenfield investments need long contract durations to secure financing, though incumbent generators should be offered power contract durations of shorter lengths to
maintain market flexibility for both the generators and suppliers who contract their
Perhaps most critically for the success of the entire power payment design is
the incorporation of reliability incentives into the product that is auctioned. An
important distinction should be made between a power payment system that pays
generators to simply deliver power and a payment that ensures that power is delivered
when the grid needs it. The current design in Peru is the latter: it pays generators
for their contribution to peak through relying on proxy calculations such as forced
7This distinction is iade in the Brazilian power sector (Putnam Hayes and Bartlett Inc and
Mercados Energ6ticos S.A., 2011).
outage rates or lowest monthly water inflows for hydro. However, the power payment
design fails to account for system need.
For example, if the lowest hydro inflow that is used to determine the firm capacity
for a hydro plant coincides with the lowest period of demand, yet the hydro facility
consistently contributes to meeting peak demand during high demand periods, that
facility is not being remunerated on the basis of the power it can provide when the
grid needs it the most. The same goes for thermal power plants. If an average forced
outage rate is used to establish firm capacity of Camisea natural gas plants, yet the
only times forced outages occur is when demand is highest - and the Camisea Pipeline
is overburdened - those generators are being over-compensated for their supply.
Simple changes to the way payments are disbursed, no matter if the current payment concept is maintained or if a new one is designed, can make the payments better
suited to encouraging generation when the grid needs it the most. Calculating the
forced outage rates based on periods of high demand, relying on ex post payments
based on generator availability during grid contingency events, or levying strong noncompliance penalties will all force generators to internalize the timing and cost of
nonavailability when they are most needed and encourage more grid reliability than
simple transfers that do not account for grid need.
The Mechanism
The main problem with the price-based security of supply mechanism that Peru has
now is that the regulator has to hope that the ideal amount of generation investment
follows from the administratively set price, something that has yet to come to bear8 .
Though a capacity payment mechanism is not inherently flawed, changes must be
made to the mechanism if the results that are sought never manifest.
The capacity payment system in Peru, like many others, adjusts generator remuneration based
on availability factors. Therefore in practice not all generators receive exactly the same payment for
their capacity, but rather they receive the same payment for their effective capacity and will for the
purposes of this analysis be considered a single price system.
A quantity-based approach, as considered here, has the advantage that the regulator can set a desired quantity and allows the market mechanism - here the auction
clearing price - to set the correct price, avoiding the Goldilocks challenge of setting
the ideal price for power based on a sought level of system reliability. Though a
fixed-quantity mechanism would be an improvement over the status quo, precaution
does need to be taken to avoid manipulation of the market by incumbents.
The Process
A design imperative for the process of conducting the power supply auctions should
include aggregated demands of all consumers, not simply individual distributors. The
economies of scale that are so important in reducing the cost of hydro cannot be
realized without large power supply needs being met through aggregated demand.
The current supply auctions fail to meet this design criteria.
It is notable that several of the aforementioned design considerations are present in
the current cold reserve solicitation scheme. Cold reserve generators, auctioning their
power under conditions similar to the design described here have consistently fetched
power payments higher than the regulated rate (Table 2.2). This price discrepancy,
the relative success at the ease of clearing those auctions, and the reliance on this
ad hoc method of securing generation capacity are all cause to reconsider the current
capacity payment mechanisms.
One feature of the cold reserve auction designs not explicitly discussed here is that
decisions are made on a geographic basis. The regulator knows that not all potential
investment locations are equally beneficial for the system. If the estimated avoided
costs of a certain power line exceed the additional power payment needed to encourage
investors to build in a place that would eliminate the need for that transmission line,
then the economically prudent decision by the regulator would be to pay a higher
power price, up to the avoided costs, to the generator that eliminates the constraint.
This type of design feature, though not advocated in full here, might be suitable for
the Peruvian system if the signal nodal price for energy prevails.
Chapter 5
Peru's remarkable economic growth is in jeopardy. Its electricity sector is facing
immense challenges in the coming months and years as rapid demand continues to
outpace generation investment, while hydro investment in particular has slowed to a
trickle. Appropriate policies and regulations in the electricity and natural gas sectors
of Peru are critical to create a sustainable investment climate that benefits investors
and consumers.
Fundamental problems exist in the energy markets due to the low price of natural
gas, and the power markets through the flawed capacity payment system. Addressing
one or both of these issues could direct the sector back on the road to prosperity, but
each reform poses unique challenges from political and regulatory perspectives.
Increasing the price of energy, by raising the price of natural gas for power generators up to the economic netback value of the fuel would again make hydro a viable
investment, but structural barriers in the supply auctions would still pose a problem
and consumers would be hit with very large increases in their electricity bills.
An alternative approach, a reform to the capacity payment mechanism, could
provide the same benefits in terms of drawing new generator investment at a much
lower cost to consumers. It would also have the additional advantage of allowing the
regulator more leeway in deciding which generation technologies should be included
in the system whether it be for policy, technical or cost reasons. This regulatory discretion is akin to Brazil's successful market structure, where the regulator determines
some socially optimal mix of generation capacity and allows generators to compete
for the market, not in the market (Putnam Hayes and Bartlett Inc and Mercados
Energeticos S.A., 2011).
If Peru undergoes these particular reforms, the power system will be able to sustain
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Appendix A
Economic Dispatch Model
The economic dispatch model used in this analysis is programmed in the General
Algebraic Modeling System (GAMS) as a relaxed mixed integer program.
A full
algebraic representation of the economic dispatch model is included here.
Generation technologies
Hydro generator subset
Variable cost excluding fuel for generation type t ($/MWh)
Heat rate for generation type t ([unit]/MWh)
Fuel price for generation type t ($/[unit])
Maximum power and installation size for generation type t (MW)
Monthly hydro availability (%)
Demand in hour h (MW)
Objective function ($)
Generation cost of technology t for hour h ($)
Positive Variables:
Power output of technology t for hour h (MW)
Minimize the sum of all variable costs for all technologies for all hours:
GC ,h
Generation cost is the sum of the non-fuel and fuel costs of each generator in each
GCth = P,h * (Cv + H, * F)
Subject to:
Total power produced by generation technologies must be less than or equal to their
maximum installed capacity:
Supply must meet demand:
EPt,h = Lh
Total energy produced by hydro units must be less than or equal to their monthly
availability factor:
Phydro(t),h < 730 * Am
Appendix B
Hydro Plant Revenue Calculations
Potential revenues for a hypothetical hydro generator were calculated using the output
of the economic dispatch model, normalized for generation capacity.
Total energy market revenues are the sum of all energy payments received per year:
R EM = MC * CF * 8760
Power payment revenue is the sum of monthly regulated power payments for generators:
RP' = PP* 12
The total cost of hydro energy generation is the fixed and variable costs of generation:
C = VC * CF * 8760 + FC
The net revenue of the generator, which is used to consider investment viability, is
the sum of revenues and costs:
+ RPP - C
Annual energy market revenue ($/kW-yr)
Annual power payment revenue ($/kW-yr)
Annual net revenue ($/kW-yr)
Average marginal cost ($/kWh)
Hydro capacity factor (%)
Monthly power payment ($/kW-mth)
Annual generation costs ($/kW-yr)
Variable O&M costs ($/kWh)
Fixed O&M ($/kW-yr)
Appendix C
Secondary Market for Pipeline
An alternative way that prices could increase to reflect the opportunity cost of natural gas is to implement a secondary capacity market for transmission on the Camisea
pipeline. Supreme Decree No. 046-2010-EM allows Osinergmin to create an electronic
auction board where owners of pipeline capacity can sell in an open and transparent
marketplace. Still the regulations governing such a market have yet to be finalized,
and for the foreseeable future gas capacity tariffs are unlikely to reflect the scarce supply and growing demand in the market. Current transportation tariffs are structured
as a flat postage stamp fee. (No Author, 2010).
Such an approach would give the generators that signed the first capacity contracts
the economic right to the scarcity rents that manifest from a secondary release market.
An alternative approach would be for the government or some other entity to hold the
capacity on the pipeline and have regular auctions for the right to use the capacity
on the line. In this way incumbent generators who currently have the first right of
refusal to the pipeline capacity would not reap the economic benefits of scarcity, but
it would rather be the government that collected the additional revenue - above the
cost of operating the pipeline - to do with that revenue whatever they wish.
Under the government-held capacity concept, the added cost of electricity that
results from increased costs to generators could be subsidized by the earnings that
the government makes from selling the capacity. Then this begs the question of why
bothering to let the tariffs for pipeline transmission reflect scarcity in the first place,
and if so why not let the current holders of capacity capture the economic rents?
If the first mover advantage that is currently bestowed to those generators that
have capacity contracts is removed, the door will be opened to more efficient new
generation to invest in natural gas plants that rely on the Camisea Pipeline. The more
efficient the generator produces electricity for a given volume of gas, the more money
the generator can pay for the natural gas and remain profitable in the electricity
This would spur a "race to the top" as incumbents and new generators
alike rush to become the most efficient, and thus operate profitably for the greatest
amount of time. This increase in fleet efficiency would minimize the cost increases to
the energy market that result from the higher costs for generators.
A secondary release market would also allow industrial consumers to reflect their
interests in gas capacity and increase the utilization of the pipeline.
are required to hold firm capacity contracts to receive capacity payments from the
system operator (Reinstein et al., 2010). These firm contracts effectively exclude
other consumers from accessing the pipeline even when the generator is not using it.
Providing the ability of industrial users and generators to reflect their time-varying
value of consuming natural gas would increase the utilization factor of the pipeline
and ensure that the maximum economic benefits that could accrue from using the
natural gas for productive purposes.