Costs of Ancillary Services & Congestion Management

Costs of Ancillary Services & Congestion Management

Fedor Opadchiy

Deputy Chairman of the Board

United Power System of RussiaUnited Power System of Russia

■ 69 regional power systems; ■ 7 interconnected power systems;■ 457 325 kilometers of power lines; ■ Near 700 power plants of installed capacity 5 MW and higher;■ Over 900 substations of voltage 220 kV and higher;■ Total installed capacity of generation over 226 000 MW;■ Peak power consumption 157 425 MW

2

Network model for SCUC,DAM,BM:■ 8503 nodes;■ 13190 branches;■ 1062 generators; ■ 269 sections

33Long-term constraintsLong-term constraints

Vast area and transmission constraints determine division of UPS into 21 free power flow zones for Capacity Market

Regional levelRetail market

Markets structureMarkets structure

Federal levelWholesale market

Price setting

Capacity Market

● Provides long-term reliability – prevents generation insufficiency

● Forms efficient structure of generation (with minimal aggregated costs)

● Provides price signals to increase regional demand depending on generation sufficiency and capital costs

Electricity Market

● Provides short-term reliability and economical efficiency

● Provides efficient allocation of load between power plants

● Provides feasibility of electrical modes

● Provides price signals for consumption efficiency

Ancillary Services Market

● Maintains reliable operations of the power system

44

Congestion managementCongestion management

■ Nodal pricing uses network model that includes transmission constraints

■ Mode feasibility is controlled at every stage of market procedures (SCUC (security constraints unit commitment) – Day-ahead market – Balancing Market) which allows to avoid overloading:

▬ SCUC takes into account predicted power system condition, interconnection condition and scheduled exchange, maintenance of generating and network equipment

▬ Day-ahead market takes into account updated power system condition, interconnection condition and scheduled exchange

▬ Balancing Market provides reliable real-time operation of power system and interconnection coordination

■ Emergency control automatics provides protection against dangerous overloads of transmission lines and cuts

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Distribution of reliability supporting processes and activities between market segments

Distribution of reliability supporting processes and activities between market segments

Electrical grid access technical requirements

Deployment of protective equipment on power system objects

No separate payments: term of technical requirements for market participant, obligatory for grid companies

Power market Primary frequency control (general) No separate payments: part of payment for provided power; payment can be reduced in case of non-compliance

Secondary load-frequency control(for hydro power plants with an installed capacity over 100 MW)

Reactive power control

Dispatcher orders execution

Energy market Load following, balancing No separate payments

Providing of operating reserves

Ancillary services market Primary frequency control (standardized)

Paid separately

Secondary load-frequency control

Reactive power control (using generators in synchronous condenser mode)

66

77Ancillary Services TypesAncillary Services Types

Ancillary Services

Market-Based Prices

Primary frequency control

(standardized)

Secondary load-frequency control

Cost-Based Prices

Reactive power control (using generators in synchronous

condenser mode)

Frequency control services: creating competition in market with lack of supply

Frequency control services: creating competition in market with lack of supply

Competition created as a result of• Setting of annual limits on payment, based on

previous year statistics and supply prediction• Specific design of tender procedures (e.g. three

proposals with most expensive bids can be rejected etc.)

• Market participants can be forced to obligatory service provision in case of unsuccessful tender (payments are based on regulated tariff)

• Transparent cost calculation methodology is used by market participants as a rough indicator of fair price

• Spinning reserves provided within frequency control services are paid separately in energy market that means increasing of price bids

88

15 45 65 85 105

125

150

200

280

335

365

420

451.

25

481.

25

511.

2553

2.5

559.

558

9.5

619.

564

9.5

849.

5

1049

.512

260.00

0.50

1.00

1.50

2.00

2.50

3.00

Supply and demand curve Supply and demand curve

ActualDemand

Submitted proposalsPrice, €

Reserve, MW

∑ (Pi × Ri ×T) ≤ L,where Pi – unit price, rubles (per 1 MW of primary operating reserve provided for 1 hour)Ri – reserve provided by unit (MW)T – time of use, hoursL – total cost of service limited by regulator, rublesi – number of units submitted

Cost calculation methodologyCost calculation methodology

■ Physically based – several tests on working equipment were conducted to study frequency control mode impact on equipment

■ Uses actual prices from equipment producers

■ Several types of costs are identified:▬ Capital costs – modernization of equipment▬ Operating costs caused by decrease of equipment efficiency▬ Operating costs caused by increase of failures and reduction of equipment

durability▬ Operating costs resulting from additional equipment maintenance ▬ Lost benefit in electricity market

1010

Change in the number of participating unitsChange in the number of participating units1111

01.01.2011 01.09.2011 01.01.2012 01.01.2013 01.01.2014 01.01.20150

200

400

600

800

1000

1200

1400

0

10

20

30

40

50

60

70

80

3643

53 5462

70604.50

722.50

897.66959.16

1,112.56

1,283.061,226.00 1,226.00 1,226.00 1,210.34 1,213.001,213.00

Number of units Reserve, MW Demand, MWMW

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Primary frequency control weight-averageprice dynamics*

Primary frequency control weight-averageprice dynamics*

1.10

1.15

1.20

1.25

1.30

1.35

1.40

1.26

1.34

1.29

1.24

1.15

01.01.2011 01.09.2011 01.01.2012 01.01.2013 01.01.2014€/(hour*MW)

*Service price is a hourly payment for 1 MW of primary operating reserve

Reactive power service (using generators in synchronous condenser mode): a fair prices in the non-competitive market

Reactive power service (using generators in synchronous condenser mode): a fair prices in the non-competitive market

■ Reactive power market: reactive power is supplied locally so usually one only provider of the service exists in the area

■ Synchronous condenser mode is a specific mode that causes expenses for generator

■ There are no reliable methods for determination of economic impacts of reactive power control

So cost-based pricing is used. The following factors are taken into account: duration of work in synchronous condenser, amount of energy consumed, prices in energy market, service quality.

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Pricing characteristicsPricing characteristics

■ Service cost is calculated using simple unambiguous equation■ Variables are measured hourly energy consumption and electricity

market prices – e.g. completely verifiable values■ Following costs are taken into account

▬ Generator consumption▬ Excitation system and power plant auxiliaries consumption▬ Energy losses▬ Costs of generator start (for thermal power plants)

■ Fixed rate of profit is included

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Reactive power service implementation effectReactive power service implementation effect

■ Before: in 2009 synchronous condenser mode was used on 69 units of 19 power plants:

▬ 64 units of 14 HPP (of capacity up to 500 MW) and 5 units of 5 TPP (of capacity up to 200 MW) were used in synchronous condenser mode for 69 000 hours in total

▬ 28 of these HPP and TPP units were used in synchronous condenser mode for more than 1000 hours each

▬ Synchronous condenser mode on one of HPP with 250 MW units was used for a total of 15000 hours

■ Service implementation▬ Two groups of applications of synchronous condenser mode usage were defined: reactive

power control (which is payable service) and all other purposes (which are in the interests of power plant and non-payable)

▬ Distinct criteria of necessity of synchronous condenser mode usage for reactive power control were formulated

■ After: in 2013▬ 65 units of 9 HPP provided reactive power service using synchronous condenser mode for

14000 hours (in addition near 300 hours of synchronous condenser mode usage for non-payable purposes took place)

▬ Usage of TPP units in synchronous condenser mode was phased down▬ Expenses on synchronous condenser mode usage were reduced significantly

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ConclusionsConclusions

■ Reliability supporting activities in UPS of Russia are distributed between different market segments

■ Electricity and capacity markets provide efficient usage of network capacity, emergency control automatics is used in case of contingencies

■ Artificial competition in the frequency control services market with lack of supply was created. This competition provides a strong incentive for further modernization of power plants’ units to meet the requirements for market participants so that we anticipate saturation of demand in 2015

■ Cost-based pricing mechanism for non-competitive reactive power service was created. Reactive power control implementation resulted in optimized usage of generators operating in synchronous condenser mode

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Thank you for your attentionThank you for your attention

Fedor Opadchiy

fedor@so-ups.ru