2013 energy sector program phase-2 project kick-off …€¦ · 2013 energy sector program phase-2...

2013 ENERGY SECTOR PROGRAM PHASE-2 PROJECT

KICK-OFF MEETING

EU IPA13/CS-02.a

Energy Market Development – Ankara, May 2019

Seminar #1 – "Influence of Renewable Support Mechanisms on

Competitive Wholesale Markets and Non-Renewable Generation”

16.05.2019, Ankara

Influence of Renewable Support Mechanisms on Competitive Wholesale Markets and Non-Renewable Generation

1. Introduction

2. Power sector restructuring and liberalization

3. RES support schemes

4. Conflict between decarbonization and liberalization

5. International Experiences handling challenges

6. Conclusions

7. Discussion and Q&A

Agenda


Liberalization of Power Markets


Liberalization of Power Markets: Turkey


Increasing role of RES-E

▪ 23.5% in 2017, worldwide.


RES-E main features

▪ Minimal marginal costs and limited ability to continually balance output

with load

▪ The incorporation of variable energy resources (VERs), such as wind

and solar, are considered the largest challenges to current market

designs

- Difficult to balance energy with load

- Sources can be very far away from loads

- Increased planning and operational needs

▪ Deployment of RES-E implies larger transmission network and better

transmission planning

▪ Existing generation capacity may exit the market


Market Functioning

▪ Previous Situation: irrelevant role of

RES-E in the market

▪ Current Situation: significant role of

RES-E in the market


1. Introduction





6. Conclusions


Agenda


Powers sector restructuring and liberalization

1. Where did we come from?

• From regulated markets to fully competitive markets,

• Objectives

• Enhance competition

• Reduce prices

• Benefits consumers

• Attract Investment required for expansion

2. Competitive market behavior

• Explanation supply demand balance

• Efficiency of price signals

• Leave investment decisions to private investors, reducing pressure on governments.

3. Limitations

• Lack of transparency

• Market power

• Market intervention→ External support to some technologies….




▪ Unbundling and privatisation progress is larger in power generation and

transmission.

▪ Some countries still have Distribution and Retail activities bundled: Argentina,

Peru and Chile, among others.

▪ While others, such as EU, Brasil, Mexico, Colombia, have separated them.

▪ Spain has a single power transmission company (REE) while Peru has 6 main

ones.




Short term (spot )

market based on offers

of sellers and (in some

cases) buyers. Bilateral

or auctions

Medium and long

term market based on

bilateral contracts

and/or Power

Exchanges

Qualified (up to

100%) end-

consumers allowed to

buy in the wholesale

or retail market

Transmission and

distribution remain

regulated activities

A System Operator

manages the

transmission system

Multiple sellers and

buyers with open

access to

transmission and

distribution networks

A Market Operator

manages the the real

time markets

(may be part of SO or

independent)

Electricity Market



2. Competitive market behavior

• Power cannot be stored in large scale, what makes it a unique commodity: production must be

equal to consumption at any given time.

• The network works as a huge net of loads in which the force operating in both senses must be

equal or the equilibrium will be broken and blackouts will appear

€/MWh

MWh

180

0

Equilibrium Q

Equilibrium P

Demand Curve

Supply Curve

Oil

NG

€/MWh

Wind, PV, Hydro

180

0

Equilibrium Q

Equilibrium P

Demand Curve

Supply Curve

Marginal Pricing and Merit Order Effect

Nuclear

LigniteHard Coal

Regulated Demand (Price-takers)

Oil

NG

€/MWh

Wind, PV, Hydro

180

0

Equilibrium Q

Equilibrium P

Demand Curve

Supply Curve

Marginal Pricing and Merit Order Effect

Nuclear

LigniteHard Coal

Regulated Demand (Price-takers)

Δ RES Q

Δ P

Yesterday

Today



3. Limitations

• Lack of transparency

• Gaming opportunities, administrative complexity, unwarranted transfer payment (when

vertically integrated still available)

• Market power

• Incumbents still hold most of the market, deterring entry of new competitors, both in

wholesale and retail markets.

• National resistance to the entry of foreign companies (national champions policy)

• Market intervention

• External support to some technologies (national coal, renewables)

• Grandfathered rights (originated in previous stages of liberalization)

• Political goals over market efficiency (e.g. Nuclear Power in the UK)



3. Limitations: Herfindahl- Hirschman Index for Wholesale and Retail Markets in EU

▪ The U.S. Department of Justice considers a

market with an HHI of

▪ less than 1,500 to be a competitive

marketplace,

▪ an HHI of 1,500 to 2,500 to be a

moderately concentrated marketplace,

and

▪ an HHI of 2,500 or greater to be a

highly concentrated marketplace



3. Turkish Situation




0

10,000

20,000

30,000

40,000

50,000

60,000

70,000

80,000

90,000

2006

2007

2008

2009

2010

2011

2012

2013

2014

2015

2016

MW

Private Hydro EÜAŞ Thermal & Others

EÜAŞ Hydro Private Thermal & Others

Public20,146 MW

Private Sector58,352 MW




▪ EUAS is still the largest generator (no IPP shall cover more tan 20% of demand)

▪ TETAS is the main wholesaler (receiving all energy from EUAS and BO/BOT/TOOR plants). Monopsonic

position

▪ Private generation already accounts for 70% of total generation

▪ Procurement:

▪ For non eligible customers, suppliers need to buy from TETAS and find non-covered volumes (if

any) in the DAM market.

▪ For eligible companies, retailers may purchase in the DAM and by means of bilateral contracts.

▪ In the past, TETAS prices have been below EPIAS for some years, since they can use Hydro to modulate

prices.

▪ In 2019, 88 GW of capacity were reached.

• By the end of 2019, 9 GW of wind are expected to be online.

• Currently, there are already 5 GW of PV installed, mostly unlicensed (microgeneration, < 1 MW).


1. Introduction





6. Conclusions


Agenda


RES support schemes

1. Rationale

◼ Why were Support Schemes required?

To mitigate market failure, as social

cost is above private cost for RES-E

To increase local supply and reduce

dependence on imported fossil fuels

To increase Security of Supply

To reduce GHG emissions

◼ Two main types of Support Schemes

Price Based: A price is set by

regulation (it directly internalizes

environmental externalities).

Quantity Based: create demand and

an environmental market (resulting

price provides the signal for

environmental behavior)


RES support schemes

1. RE trends


RES support schemes

1. RE trends

▪ Future installed VER capacity in the EU according to the three scenarios currently

considered by ENTSO-E.


RES support schemes

2. Power sector policies

▪ Challenges

▪ Extra costs (in the past)

▪ VRE management

▪ System updates

▪ Need of new price signals

▪ Lack of profitability of thermal capacity

▪ Generation moves to the distribution

level


RES support schemes

3. Renewable power policy instruments – strengths and limitations

• FIT/FIP shelter producers from

market signals, giving them no

economic incentive to adapt

project features (such as location,

installation design, or actual

operation) to supply and demand

• Those energy sources that have

reached maturity should be

increasingly exposed to market

signals

• Support schemes needed to be

mixed and made more responsive

to price signals.

• Moving renewable energy sources

away from subsidies and

integrating them into the market

will reduce market distortions,

improve the functioning of the

internal market


RES support schemes

3. Renewable power policy instruments – Trends towards auctions

1. Real price discovery

2. Flexibility

3. Greater certainty in

price and quantities


RES support schemes

3. Renewable power policy instruments – make RES very competitive

• No subsidies may be needed any more


RES support schemes

4. Results:

• RE production has increased

in all European countries in

recent years

• Great regional differences

appear due to different factors:

– Generation mix

– Availability of RE

resources (hydro most

noticeably)

– Specific countries’

promotion schemes

◼ European targets


RES support schemes

4. Results:

0%

10%

20%

30%

40%

50%

60%

2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016

Share of renewable energy in electricty generation

European Union - 28 countries

France

Italy

Portugal

United Kingdom


1. Introduction





6. Conclusions


Agenda


Conflict between decarbonization and liberalization

1. Consequences and risks at a glance:

• The rise of RES has resulted in an increase in critical load-following requirements for

conventional plants

• Ancillary services are becoming increasingly scarce as conventional plants are displaced or exit

because of inadequate revenue

• Costs of increased grid investments for connection and transport

• Potential curtailment of solar and wind due to inability of the system to absorb them

• The advent of intermittent renewables with high upfront capital costs but very low short run costs

has led to a reduced role for the market in guiding investment.

• Governments now dominate by setting the subsidy regimes and capacity payment schemes

• Pre‐mature exit and inadequate entry of flexible dispatchable generation in the future is clearly

of concern to system operators and regulators.

2. Needs for the future

• Better price signals

• Better incentives for RES investment and operation, and

• Greater system flexibility

When significant quantities of generation are partially supported by out‐of‐market revenues there

is no reason to believe that the energy market will support an efficient equilibrium of subsidized and

unsubsidized generating technologies



3. Displacement of Fossil Fuels

• The share of renewables in EU-28 electricity production has increased remarkably over the last

decade to reach 28% in 2015, driven by generous subsidies and priority dispatch connection

terms.

• However, raising the renewables share to 55%+ by 2030 will be challenging without substantial

modifications to the current “1st generation” market design.

• In the short run, the addition of zero marginal cost RES shifts the supply curve to the right,

causing the wholesale price and capacity utilization rates of coal- and gas-fired plant to fall.

Decrease in average wholesale energy prices, studies find an increase in the relative

revenue from ancillary service and capacity markets, and scarcity price events



3. Displacement of Fossil Fuels



4. Reduction on MP

• Price reduction and displacement of fossil production will result in lower usage rates for flexible,

baseload fossil capacity.

• Viable projects may not materialize for fear that future users will not be willing to pay the price.

• Long-term bilateral contracts may arise as a solution, to guarantee prices for both RES-E and

conventional sources.

• E.g. a generator with a mixed portfolio (fossil base load and solar) may close a PPA with

prices that guarantee the viability of both of its assets)

• If wholesale prices are capped (i.e. no scarcity prices appear), investors in fossil generation will

have less revenue recovery opportunities

• It may be required to include schemes that guarantee investments in security of electricity

supply and generation adequacy

• Capacity Payments

• Demand-side mechanisms (demand reduction)

• Improved Cross border trade

• Storage of energy (large-scale pumped hydro and small-scale battery-based solutions,

such as Terna in Italy).



4. Reduction on MP



5. Low or zero energy prices more frequent

• Prices will vary according to intermittent generation, leading to zero and (when possible) even

negative prices.

• On the other hand, scarcity prices will increase largely unless capped.

• Effect on retail markets: price volatility has a negative impact on possible new-entrants to retail

markets, favoring incumbent players and reducing the level of competition in the market.

Bilateral contracts with RES-E generators can help them secure prices below DA market.



6. Demand profile implications



7. Increase on ancillary services costs and flexibility value

• Intermittency of renewable resources requires that a large level of fast-responding capacity is

connected to the grid at all times.

• Participation requirements for RES-E to be eligible for Ancillary Services

• Technical viability allowed by Power Electronics improvements

• Portfolio bidding and expanding the scope of balancing markets can significantly reduce the cost

of balancing variable renewable generation (such as the case of the Expanding Energy

Imbalance Market (EIM) in the western U.S. or CBT in the EU)

• Moreover, regional wholesale power markets have shown to accelerate growth of demand

response and greatly facilitate renewable generation investment in wind-rich states

• RES-E variability affects operation of the system in the following levels

• Grid Balance and Flexibility

• Frequency Control

• Transient Stability

• Short-circuit Current



8. Increase on ancillary services costs

and flexibility value

Grid Balance and Flexibility

• Increase in coupling needs to

CCGTs due to demand fluctuations

(peak-valley) and PV production

during central hours of the day

(doble-valley load curve)

• Time reduction for variations

• May require innovations to diminish

technical mínimum capacity of

plants

• Plants may experience increases in

unavailabilities due to more O&M

requirements.

• Increase in storage, demand

response and participation of RES-

E in AS would alleviate the

problem.



9. Increase on ancillary services costs

and flexibility value

Reserves

• Lowest reserve values (downwards)

of future systems will appear on

central hours of the day (higher PV

generation), since few groups are

connected and close to their

technical mínimum while lowest

hydro production. Storage, if

available, is at that time consuming.

• Lowest reserve (upwards) likely to

appear during initial hour of the

morning and final hours of the day

(no PV), while highest values during

PV production.

• Increased storage and demand

response are favorable.




• Transient Stability: need to increase requirements for RES-E to couple with

tension dips and to be able to inject reactive power.

• Frequency Control: higher penetration of RES-E requires measures to

increase inerthia in the system, such as syncronous compensators.

• Short-circuit current: highest/lowest values will increase, but can be

compensated with higher must-run levels for synchronous generation and a

more meshed grid.




Source: CEER



11. Risks of shortage or unreliable supply

• Larger volumes of capacity are required to offer the same firm energy.

• Conventional capacity is also required to act as back-up.

• Capacity Markets developed in the US (PJM, New England, New York) and in the process in

Canada(Alberta, Ontario and others are now moving from energy‐only markets to energy plus ca

pacity markets) plus some European experiences on capacity payments (SP, IT, UK).

• Capacity markets require the establishment of minimum generating capacity targets required for

reliability constraints and a long-term market that determines the “capacity prices” to be received

by generators if they can provide availability to supply power or ancillary services

• Other markets rely in energy only mechanisms (such as ERCOT in Texas) with very high or no

price caps.

• Early retirement is also a concern; CPUC (CA, USA) is currently considering the adoption of a

five-year capacity requirement for utilities (currently, one year only).

• Some international experiences (Spain, Mexico) have shown the problems related with lead

times (timely commissioning of new capacity). As a result, capacity tenders should incorporate

clear constraints on access to the grid and construction dates.

• Nodal pricing systems can help to better signal locations in the network, by avoiding

concentration of resources in some points (as it is the case in South Spain) and by avoiding

expensive re-dispatching of units.



12. Impacts from high RE (sample simulations in USA markets)

Displaces Coal and Natural Gas Generation Low Energy Prices Become More Frequent

Annual Average Energy Prices Decline Diurnal Price Profiles Change

Prices more Volatile as VRE Increases

Ancillary Service Prices Increase


dd


13. ExamplesWholesale price effects simulations USAGermany wholesale price evolution

Substantial flattening in German

diurnal price profiles between

2000-12 that coincided with strong

deployment in solar capacity

There is a very clear

connection between

the growth of solar

generation and this

distinct change in

hourly price patterns.



14. High renewables in the system

Supply side decisions Demand side decisions

▪ Scarcity pricing will help to sustain

flexible resources

▪ Development of long-term auctioning

for new capacity and capacity

payments for existing thermal

capacity.

▪ Emissions trading schemes (cap and

trade), with relatively high prices for

GHG permits.

▪ Deployment of distributed generation

and storage solutions within the

distribution network and beyond-the-

meter.

▪ Locational pricing systems will help

to achieve optimal development of

the system.

▪ Long-term planning for transmission

network is also required.

▪ Introduction of RPS and RPO

▪ Demand aggregators and

participation of demand in load

management.

▪ Lower capacity requirements for

interruptible demand

▪ Time-of-use tariffication to swift

consumption off the peak.

▪ Development of Beyond-the-meter

PV facilities, reducing peakedness

▪ Domestic Storage solutions

▪ Deployment of Electric Vehicles as

flexibility solutions

▪ Creation of Consumer Agrupations

to promote mass supplier changing

process

▪ Requiring 100% renewable supply


1. Introduction





6. Conclusions


Agenda


International Experiences handling challenges

1. Some of the measures under consideration to offset the impact of renewables in the wholesale

markets

A. Policy measures

• The general trend is to develop other products (such as ancillary services, flexibility, demand

response, reliability, capacity, and green certificates), which are accounting for an increasing

proportion of total system costs.

• There is growing recognition that in the long run an energy‐only market with price caps will

not yield adequate revenue to deter premature exit of dispatchable generating capacity or to

attract efficient entry of new dispatchable generating capacity (or substitutes for it like storage) t

hat are well matched to the operating attributes of a system with intermittent generation at scale

• Partial re‐integration through government mandates, competitive procurement and

long‐term contracts.

B. Technical measures

• Interconnection

• Storage

• Demand side management

• Self-consumption with inverters



2. Ontario- from 49 terawatt-hours (TWh) of coal and gas generation in 2003 to 5.9 TWh in 2017.

• Energy markets: Baseload energy prices remain low in many hours as markets continue to

decarbonize… but the emerging influence of scarcity pricing, storage, and demand response will

produce much higher prices during shortage events, thus improving incentives for fast-

responding and peaking resources.

• Flexibility and ancillary services: Continue to expand in both volume and price, as well as

playing a key role by supporting energy prices during scarcity and peaking events.

• Capacity markets: Prices for capacity may decline through transition periods due to oversupply

conditions; but over time, capacity prices are likely to increase to retain adequate supply

Large increase in prices, due to non-

adjustment of the market to increasing de-

carbonization.

Complementing the existing energy market

with additional wholesale market components

for flexibility, capacity, environmental attributes,

and customer and distribution system services

will help to send clearer signals of value to

consumers and producers



3. California- first mandatory programme in the US for de-carbonization

• De-carbonization and liberalization had been separated (unlike in Europe).

• The program seeks an 80% reduction of GHG emissions by 2050 vs. 1990.

• Tools employed

• Cap-and-trade GHG emission market

• Renewable Portfolio Standard of 50% by 2030 for suppliers.

• Net-energy-metering scheme, offering full retail price for every kWh fed into the grid (very

high)

• Community Choice Aggregators (CCA) (2 million customers) to promote en masse

switching

• Large impact of C&I customers signing 100% green PPAs (Google, Apple, Tesla, etc.).

Over-generous net metering regulation, that promotes cross-

subsidization between solar and non-solar customers.

Fast-increasing solar capacity imposes large constraints on

how to tackle the duck curve.

Fast increasing PPAs for RES-E

Growing competition between prosumers and utilities, despite

lack of liberalization (paralyzed after 2000-2001 power crisis).



4. Texas- Energy only market

• Only market in the US designed as a energy-only market,

together with high levels of wind penetration (17%). Thus, it

has no mechanism to provide adequacy of supply in the

long-term.

• Besides, it is largely isolated from the rest of the US, so it

acts as a power island.

• Most power is thermal based (NG and coal); prices driven

by Henry Hub and vast flexibility of resources.

• They system presents continued growth in consumption

and peak demand.

• Locational prices to show transmission congestion.

• Large degree of retail competition and decreasing retail

prices.

• Reliability must-run agreements, outside the market, can be

entered to prevent early retirement of capacity.

• The Competitive Renewable Energy Zones resulted in7 bn

of new transmission projects, enabling wind production.

• It remains to be seen if they can provide capacity in the long

run.

Ability to efficiently plan and

operate the system based

on transmission planning

and primarily market-based

operational mechanisms

(locational prices and

forecasts)



5. Technical measures: Implications and

examples

• Full co-optimization in the real-time market of

energy and ancillary services, directly

accounting for the operating reserve demand

curve in the system dispatch

• Intra-day markets enabling a more decentralized

balancing of deviations in the system by market

participants: new cross border Intra-day market

in the EU, allowing for real time continuous

trading.

• Use of Interruptibility services for large

customers (those consuming more than 40 MW

and 5 MW)

• Participation of RES-E in Ancillary Services

• Creation of Regulation Areas and Portfolio

bidding

• Requirements to be resistant to voltage dips for

wind generators




examples

Technology Tertiary Regulation(MW)

SecondayRegulation (MW)

Of total CapacityInstalled

Of total CapacityInstalled

Hydro 14.985 14.956 87% 87%

Wind 10.442 230 46% 1%

CSP 30 0 1,3% 0%

Biogas/Waste 20 0 2,7% 0%

PV 0 0 0% 0%




examples



5. Changing the paradigm? Smart contracts, blockchain…


1. Introduction





6. Conclusions


Agenda


Conclusions

1. Background

• Development of intermittent, price-taking and/or close-to-zero variable cost generation has

jeopardized the way traditional players act in the market

• RES integration is not only about RES, but how the system will provide the correct incentives to

all technologies so as to compete in a level playing field

• Market design changes and new innovative products are likely to appear in order to address the

new paradigm

2. Key Considerations

• How to foster efficiency and effectiveness through policy schemes, from support schemes to

market based products:

• Through policy instruments for installing new RES plants

• Through policy instruments for the market integration of current RES plants

• Realistic solutions to current design status => Decision tree and detailed roadmap to transit the

change in an optimal manner

3. Market Design

• Capacity remuneration mechanisms

• Responsibility for electricity grid balancing

• Procurement and use of flexible capacity

• Increased backup and storage capacity

• Demand response measures

(including intermittency)

• Improved RES injection forecasting mechanisms

by the TSO

• Implementation of Intraday or close to real time

markets

• Connection charges

• Long Term Access and Congestion Management


Future of the Sector

• Smart Grids and Connectivity – A change of paradigm

▪ Widespread implementation

of smart meters and smart

data management (smart

grids) will enable faster and

more transparent

interactions between the

power market and the end-

user.

▪ The end-user will become

the core of the system.

Prosumers, storage, smart

meters, smart contracts, etc.

▪ Bidirectional interaction is

key, and the definition of

roles in the new end-user

centred paradigm is not

clear yet.



• Smart Grids and Connectivity – A change of paradigm

– New available data on consumption and use of the network (at

distribution level) would enable, among others:

– near real-time pricing of electricity to serve demand, rendering

the electricity market more representative of real generation-

consumption profiles, and

– the application of locational marginal prices (nodal prices) at

distribution level.

– Therefore, the market should become increasingly less regulated

and central agents will reduce their activity, leaving room to

decentralised automatic or semi-automatic dispatching and

trading systems.



• New technologies – Distributed Generation– Several RES based generation technologies have already achieved cost levels that

allow them to compete with end-user retail tariffs (“plug parity”) and even with utility-scale conventional generation (“grid parity”).

– This has motivated the developed (in its early stages now) of distributed generation and the emergence of the “prosumer” role, which is basically a consumer that also produces its own electricity (covering part of its production, all of it, or even producing in excess and selling to the system).

– The key to the technological jump at the distributed generation level will be storage. Right now, storage technology is not advanced enough to save large volumes of electricity for a long period. It is costly and with limited capacity. So now distributed generation is relying on the main system as (i) back-up and (ii) to “store” excess energy.

– The development of smart meters, smart contracts and improvements in storage are enabling fully distributed electricity supply as a replacement for the current paradigm. Buildings, communities, cities or areas could rely on their own local resources to supply their own energy needs in a balanced and automatic manner.

– The transmission grid would be largely unused (just as back-up and for minor inter-area exchanges). Utility-scale generation risks not being interesting anymore.


Discussion and Q&A


Back Up Slides

◼ Generators: large generators can sign bilateral contracts and/or participate in the wholesale electricity market as direct agents, individually or bundled. Small generators may sell directly to distribution companies, retailers or consumers.

Incumbent vs IPP: incumbent generators typically belong to the vertically integrated utility, or the post-unbundling successor companies; they may remain public or be privatized. Independent Power Producers, in opposition, are privately funded new entrants.

Merchant vs PPA: Merchant plants sell their electricity in the competitive wholesale electricity market. But power generators can also sign a Power Purchase Agreement (bilateral agreement) by which they commit part of all of their output to a specific buyer and for a long period of time (approx. 10-30 years).

◼ System Operator: coordinates operations in the electricity system (at transmission or at distribution level). Typically refers to the transmission level system operator (wholesale). 4 types of organisation defined (in Europe by Directive 2009/72/EC and in the US by the FERC Orders) ISO model: an Independent System Operator (fully independent from generation and supply –

legally/functionally/control) operates the transmission system under a lease agreement with the Transmission Network Owner or Transmission Asset Owner. Typical in the US and in some EU countries.

ITO model: network operation is not structurally unbundled from supply activities, while network ownership remains with the same entity as the operator.

ITO+ model: vertically-integrated transmission system that includes provisions that ensure a higher independence status for the operation of the system than that of ITO.

Additionnally there is a fourth model, the RTO model.

RTO model: the Regional Transmission Organization is responsible for electric transmission grid operations, short-term electric reliability and transmission services within a multi-state region. Typical in the US.

◼ Market Operator: agent in charge of receiving electricity supply offers and demands. It is in charge of matching them (similar to the stock market) and settling transactions (internally or through external clearing houses).

Multiple market schemes are possible: Public integrated utility: the utility itself runs the market, may be including bilateral agreements

with third parties (IPPs).

Single Buyer/Principal Buyer: all electricity (single) or most electricity (principal) is bought/sold by a single central agent.

Free Market (voluntary or mandatory): competitive market where market agents freely trade electricity. Participation in the market may be voluntary or mandatory (bilateral agreements, done “over-the-counter”, are usually just declared).

And different types of market exist: Day-ahead

Intraday

Ancillary Services

Capacity markets

Futures/options markets

◼ Network business: transmission and distribution Considered natural monopolies in view of high capital investements, economies of scale and density. At transmission level different schemes are possible: Transmission System Operator (TSO) that owns,

operates and maintains the transmission grid (or parts of it or a duo of Transmission Network Owner (TNO, who invests and owns) and Independent System Operator (ISO, that operates and maintains).

At distribution level, it is impractical to have ownership and operation separate, therefore Distribution System Operators (DSOs) typically have both simultaneously.

Key aspects are: − Third Party Access: non-discriminatory access to network services (connect and use)− Network planning and investment management (regulation and incentives)− Integration of distributed generation and smart grid capabilities

◼ Retailers: buy electricity from the market and sell it to end-users (consumers)

◼ Traders: act as intermediaries in the electricity market and can apply speculative strategies; they contribute to market liquidity.

◼ Final consumers: buyers of electricity, either from suppliers or directly from the market (qualified consumers). If they also generate, the term “prosumer” applies.

◼ Background California's wholesale power market started in March, 1998. In

summer of 2000, retail electricity prices sky-rocketed and generation capacity shortages forced temporary power outages in northern California

◼ What happened? Very high wholesale spot prices

Forced power shortages during peak times

Lack of financial stability of the three major investor-owned utilities (Pacific Gas and Electric (PG&E), Southern California Edison (SCE), and San Diego Gas and Electric (SDG&E)).

◼ Why happened Wholesale prices reached 270% of 1999 prices during summer 2000. companies were

prevented from entering long-term contracts, but had to buy all their power through CalPX, what increased their exposure to s/t fluctuation of prices.

The three majors passed those prices through to retail consumers but were forced by law to respect a limit of 6.5 c$/kWh for the energy term of bills.

Financial Stability of the 3 companies rapidly deteriorated, given the inability to pass high prices on to consumers and given that some IPPs stopped selling power to them (for their lack of credit worthiness)

◼ The reasons California largely relied on imports: 7 to 11 GWs of hydro capacity located on Northern

States. No new capacity had been installed in California since 1990, against a demand increase

of 11%. The transmission lines connecting north and south California was congested during peak

times. During 2000, poor hidrology conditions led to 10 GW being temporarily out of

operation.

◼ Lack of new capacity The Californian energy only-market was not able to deliver the needed

investments in capacity (and transmission capacity)

The problem was worsened by the attitude and ulterior fall of Enron, which caused one of the biggest financial scandals in the US.

◼ Outcome California established a capacity mechanisms to guarantee new

investments in generation and transmission capacity.

Price Caps were imposed on s/t markets (AS included)

Long-term contracts were also approved in order to prevent short-term fluctuations to be passed on to final consumers.


Case Study: 100% renewable systems: Costa Rica – generation mix and

price of energy

• Costa Rica, with its high hydro generation resources (around 70% of supply), its already a highly renewable country.

• National targets is to have 100% of electricity from RES by 2021:

– 76% Hydropower

– 15% Geothermal

– 9% wind-biomass-solar

• Costa Rica generated 99% of its power from renewable sources in 2016

• CR success: “solutions to cope with variable renewable generation lie in diversifying and using complementary renewable sources, such as wind and hydropower, using smarter grids to manage variations better, and having more interconnections to allow for electricity exchanges that make it possible to take advantage of flexible resources and complementarities at a regional level.” (IRENA)



price of energy

• Framework and Policy for RE in Costa Rica

– RE Auctions and Net Metering are the key support schemes in CR.

– Increased penetration of renewable energy, particularly in

distributed generation, is expected at Costa Rica in following years.

An important part of this generation will be of non-controllable

nature (solar PV).

– This level of penetration poses several challenges to the economic

balance and the secure and reliable operation of the power system.

Particularly, analysing the impact of RE requires:

• (i) assessment of suitable business models to ensure the sustainable

development of such facilities

• (ii) assess potential revenue losses from the utilities and/or modification in the

tariffs to reassess the economic balance,

• (iii) reliability of the system and

• (iv) proper regulation.



price of energy

• RES-based Distributed Generation in Costa Rica

– The current regulatory framework allows the development of

GD projects for self-consumption, but does not allow these

developers to obtain any economic compensation for any

surpluses that may exist.

– There are no minimum performance requirements and / or

GD protections that are mandatory. They must be negotiated

between the producer-consumer and the distribution

company on a case-by-case basis.

– Current regulation states that only 49% of the total energy

generated can be used to offset consumption during non-

daylight hours.



price of energy

• RES-based Distributed Generation in Costa Rica

– Since, power sector supply in CR is carried out by a number of

distribution companies and each jurisdiction has its own supply and

access tariffs, a dedicated analysis for each area is needed.

• RES feasibility depends on generation and consumption profiles. A Solar PV

installation will benefit Customer 2 more than Customer 1:

0.000

0.005

0.010

0.015

0.020

0.025

0.030

0.035

0.040

0.000

0.002

0.004

0.006

0.008

0.010

0.012

0.014

Customer 1 Customer 2Daytime (sunlight) Daytime (sunlight)



price of energy

• Prosumer behaviour – generation/consumption profile for

Solar PV


Case Study: Investing in Transmission Assets: regulated framework vs

merchant schemes

• Merchant Scheme: UK - Norway Interconnector

– Statnett and Britain's National Grid will build a 1,400-megawatt North Sea Link

interconnector by 2021.

– Total Cost of approx. 2 billion Euro.

– Target: to optimise time-wise production and improve use of hydro in Nordic

countries and reduce generation costs in the UK.


Case Study: Investing in Transmission Assets: regulated framework vs

merchant schemes

• Project structuring:

– Equity: National Grid North Sea Link Limited (UK) and Statnett (Norway)

– As a EU Project of Common Interest (PCI) it will have access to the Connecting Europe Facility (CEF), the EU's €30 billion fund.

– British “cap-and-floor” system applied as per the Ofgem. Merchant scheme with certain regulatory support: hybrid.

• 25-year long regulatory framework that limits the investment downside risk by providing a revenue cap and floor for interconnector projects: developers receive a top-up if revenue falls below a set level, while any revenues above a set upper level are passed back to the regulator and to consumers.

– Capable of transmitting 12.3 TWh per year.

– According to Ofgem, Base Case scenario the cable would contribute around £490 million to the welfare of the United Kingdom and around £330 million to the welfare of Norway.

– Net export to the UK via North Sea Link is projected to be about the 10 TWh, i.e. almost all of the interconnector's annual capacity as the price differential would justify the interconnector.

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