ASCE 48-11 Design of Steel Transmission Pole Structures

WESM 101

The Philippine Philippin e Power Market The EPIRA reform agenda promote competition and choice

Private sector participation in power generation generation with oligopson oligopsonyy by NPC and Meralco

State monopoly in generation and transmission

1970

1980

1990

Power Supply Crisis

2000

Institutional reforms: ERC, PSALM, Transco, etc (2001)

Electric Power Industry Reform Act

Separation of generation  from transmission (2003)

Privatization of NPC generation (2006)

Creation of WESM (2006) Transmission  privatization thru NGCP (2008) Competition in generation (2006)

Retail Competition and Open  Access (2013)

The Philippine Philippin e Power Market The EPIRA reform agenda promote competition and choice

Private sector participation in power generation generation with oligopson oligopsonyy by NPC and Meralco

State monopoly in generation and transmission

1970

1980

1990

Power Supply Crisis

2000

Institutional reforms: ERC, PSALM, Transco, etc (2001)

Electric Power Industry Reform Act

Separation of generation  from transmission (2003)

Privatization of NPC generation (2006)

Creation of WESM (2006) Transmission  privatization thru NGCP (2008) Competition in generation (2006)

Retail Competition and Open  Access (2013)

The Philippine Philippin e Power Market: Value Chain has evolved under EPIRA*

Generation •

•

•

•

•

Transmission

Open & competitive

•

ERC requires that it approves the PSA for a DU’s captive customers

•

Operates under WESM

•

No cross-ownership in Transmission No company can own, operate and control 30% of installed capacity of any grid, or 25% of the national capacity

•

•

Franchised & Regulated common carrier business Subject to rate-setting powers of the ERC National Grid Corporation of the Philippines (private consortium)

Distribution •

•

•

•

Open access transmission system

DU Regulated Retail Distribution Services

Franchised & Regulated common carrier business

•

Subject to rate-setting powers of the ERC

•

Non-discriminatory distribution open access No cross-ownership in Transmission

Captive Market •

DU/EC business segment for sales to Captive Market

•

•

(See contestability thresholds below)

No DU may source more than 50% of its demand from an associated firm

Local RES

No cross ownership in generation and /or distribution

End-users with demand =1 MW Contestability threshold reduces to 750 kW by Jul 2016 and to 500 kW by Jul 2018

Retail Electricity Supplier (RES) •

Generation

ERC licensed

End User Market 

Retail Supply 

Wires •

Distribution Retail Price to Captive Market subject to ERC regulation (including wires charges to RES)

•

•

Contestability threshold goes down from 1 MW to 750kW after 2 years ERC may further reduce contestability

The Philippine Philippin e Power Market Comparative Policy & Regulatory Regimes Pre – EPIRA •

Generation Mix

• •

• •

State monopoly in generation and transmission (NAPOCOR) Government plans for fuel diversity and energy autarky Government Government has dirigiste oversight on what gets built and how plants are run •

“least cost” development planning

•

dispatch based on economic merit order

Bundled generation and transmission (NAPOCOR tariff) Regulated by ERB using RoRB RoRB regulation (recovery (recovery of actual costs; subject to efficiency efficiency standards) standards)

EPIRA • •

Generation sector is open and competitive Generation Generation mix mix and what gets gets built are driven driven by the power market: Bidding Merit order in the WESM PSAs by DUs and Contestable Customers Renewable Energy Act imposes RE quota (RPS), subsidies (FIT) and priority dispatch of VREs • •

•

•

•

•

Power Rates

Unbundled: generation, transmission, distribution, gov’t charges (taxes, UCME, FITALL) DU End-user generation rate is composite of PSA charges approved by ERC and WESM Only the generation rates for captive customers and rates for wires services are regulated: ERC requires DUs to conduct CSP for PSA for captive market PSAs of contestable customers do not require ERC approval to be implemented Regulation is based on full recovery of prudent and reasonable economic costs •

•

•

The Philippine Philippin e Power Market EPIRA aims to bring supply competition and choice at the household level

•

WHOLESALE MARKET (Luzon – Visayas Grid)

NPC IPP

Department of Energy (DOE) Policy making Planning Market Establishment Energy Regulatory Commission (ERC) EPIRA enforcement enforcement Rate setting (NGCP, DUs) Quasi-judicial power on Competition CPCs, COCs, Certificate of Contestability

Market Operator

•

PEMC

• •

•

WESM SELLERS Generator 

System Operator

NGCP Wholesale  Aggregator 

IPP  Administrator 

• •

DU IPPs •

Meter Service Provider

•

NGCP

RETAIL MARKET (Distribution System)

WESM BUYERS Direct Connect

•

RES

RETAIL SELLERS

Distribution Utility

Local RES

Contestable Customer

Captive Customers

Contestable Customer

RETAIL BUYERS

•

Meter Service Provider(s)

DUs

The Philippine Power Market The Luzon Grid centers in supplying the requirements of Meralco

The Philippine Power Market The Wholesale Electricity Spot Market (WESM): Luzon & Visayas grids

GNPower Masinloc

~

~

Sual

Luzon Grid

~

Magat

Ambuklao

~

~

Visayas Grid

Binga

~ Naga Coal

North West (3,532 MW)

     ~ Subic

~ Limay

North (1,820 MW)

~

     ~

~

Angat

Bohol Diesel

~      ~ TMO SLTEC

~

Calaca

~ South West (2,326 MW)

     ~

~

     ~

     ~

Unified Leyte

Malaya

~ South East (2,906 MW)

South (1,278 MW)

     ~

     ~

Kalayaan Quezon

     ~ Cebu EDC

Leyte (710 MW)

Central (1,197MW)

Meralco

~

Cebu (862 MW)

Bohol (25 MW)

     ~

CPPC

~

~ ~

Pantabangan Casecnan San Roque

Bauang

SPC

     ~

     ~

Toledo

KEPCO

Negros (285 MW)

     ~

     ~

Negros Geo

Sacasol

Pagbilao

~

Panay (521 MW)

     ~

     ~

SPC Island PEDC

     ~ Trans Asia

The Philippine Power Market The Wholesale Electricity Spot Market (WESM): Luzon & Visayas grids Capacity Distribution by Fuel Type

Capacity Distribution by Control

The Philippine Power Market The Buyers: Captive and Contestable Market

The Captive Market •

The Captive Market are the end-user customers of DUs whose average demand is less than 1,000kW (the

The Contestable Market •

current “Contestability Threshold”) •

•

Sec 23: The DUs have the obligation to supply electricity in the least cost manner to its captive market subject to the collection of retail rate duly approved by the ERC. Sec 25: Retail rates shall be subject to ERC regulation based on principle of full recovery of prudent and reasonable economic costs incurred, or such other principles that will promote efficiency as may be determined by the ERC

•

DUs secure PSAs effectively on behalf of their customers

•

ERC requires CSP for DU PSAs

•

•

•

Threshold”)

Relevant EPIRA Provisions: •

PSAs require approval by the ERC before these can be implemented PSA contract prices are on full pass-through(no-gain-noloss basis) except any portion disallowed by ERC DUs are allowed to recover from their end-users their approved PSA charges and WESM purchases

The Contestable Market are end-user customers (or those directly connected to the grid) whose average demand is at least 1,000kW (the current “Contestability

•

•

•

•

•

•

The Contestability Threshold reduces to 750 kW by July 2016 and to 500 kW by July 2018 Contestable Customers may secure PSAs from licensed Retail Electricity Suppliers (RES) or from the DUs Local RES; The DUs will continue to provide Distribution Wheeling Services Contestable Customers are solely responsible for securing their supply; in the absence of a RES, a Contestable Customer may be supplied by ERC designated Supplier of Last Resort (SOLR) Any WESM requirement of a Contestable Customer is secured through its RES RES PSAs do not require ERC approval to be implemented The Contestable Market size is expected to grow as the Contestability Threshold is reduced (~ 35% when threshold reaches 500 kW)

The Philippine Power Market Captive Customer Generation Cost DOE Policy/ERC Rule Contracting Level

Y%, X% DUs Contracting Strategy

1 WESM Y% @ S

Power Rate Y * S + X *B

PSA X% @ B

S Spot Price Volatility

Scarcity

Notes: S  – spot price B  – Bilateral Contract Rate Y – percent share bought in WESM X  – percent share under contract

Regulatory Intervention

Abuse of Market Power

OLIGOPOLY • • •

High Market Concentration (HHI) Pivotal Plant Price Setting Plant

Price Cap

Must Offer Rule

2 Primary Price Cap Demand-Side Determination

VoLL = GDP/kWh

Anti - Abuse Of Market Power

Supply-Side Determination

Security Plant Selling Rate

Secondary Price Cap

4

“too high too long” “Perfect Storm”

Method/ Application

• • •

Events Malampaya S/D El Nino Elections

Rationale

3

Generation Cost US EIA April 2013 Report Technology Adavance Pulverized Coal (APC) Adavance Pulverized Coal APC with Carbon Capture & Sequestration APC with Carbon Capture & Sequestration Natural Gas Combined Cycle (NGCC) Advance Generation NGCC Adavanced NGCC with CCS Conventional Combustion Turbine Advanced CT Integrated Gasification Combined Cycle Integrated Gasification Combined Cycle Advanced Nuclear Biomass Combined Cycle Biomass Bubbling Fluidized Bed Fuel Cells Geothermal - Dual Flash Geothermal - Binary Municipal Solid Waste Hydroelectric Pumped Storage Onshore Wind Offshore Wind Solar Thermal Photovoltaic (PV) PV - Tracking PV - Tracking with 10% storage PV - Tracking with 20% storage

Fuel Coal Coal Coal Coal Gas Gas Gas Gas Gas Coal Coal Uranium Biomass Biomass Gas Geothermal Geothermal MSW Hydro Hydro Wind Wind Solar Solar Solar Solar Solar

Nominal Capacity, kW   650,000   1,300,000   650,000   1,300,000   620,000   400,000   340,000   85,000   210,000   600,000   1,200,000   2,234,000   20,000   50,000   10,000   50,000   50,000   50,000   500,000   250,000   100,000   400,000   100,000   20,000   150,000   150,000   150,000

Notes: Capacity net of auxiliary load Capital cost excludes financing costs (e.g., interest during constructions, bank fees) • •

Nominal Heat rate, BTU/kWh   8,800   8,800   12,000   12,000 7,050   6,430   7,525 10,850 9,750   8,700   8,700 N/A   12,350   13,500   9,500 N/A N/A   18,000 N/A N/A N/A N/A N/A N/A N/A N/A N/A

                                                 

Capital Cost Fixed O&M Cost $/kW $/kW-year 3,246   37.80 2,934   31.18 5,227   80.53 4,724   66.43 917   13.17 1,023   15.37 2,095   31.79 973   7.34 676   7.04 4,400   62.25 3,784   51.39 5,530   93.28 8,180   356.07 4,114   105.63 7,108 6,243 132.00 4,362 100.00 8,312   392.82 2,936 14.13 5,288 18.00 2,213 39.55 6,230 74.00 5,067 67.26 4,183 27.75 3,873 24.69 4,054 4,236

Variable O&M, $/MWh 4.47 4.47 9.51 9.51 3.60 3.27 6.78 15.45 10.37 7.22 7.22 2.14 17.49 5.26 43.00 8.75 -

Generation Cost US EIA April 2013 Report

Notes: Capacity net of auxiliary load •

Generation Cost Base-load, Mid-Merit & Peaking Plant Cost T ec hn ology Capacity Capital Cost Fixed O&M Cost Variable O&M

Ad vanc e CT

N G C CG T

Ad vanc e P C

MW

210.

620.

650.

US$/kW

676.

917.

3,246.

US$/kW-year

7.04

13.17

37.80

0.0104

0.0036

0.0045

•

•

US$/kWh

Heat Rate

BTU/kWh

9,750

7,050

8,800

Fuel Cost

$/MMBTU

14.51

14.51

3.04

20

30

Project Life

Years

Cost of Capital

%

15%

15%

Low Fixed cost High variable cot

30 15% • •

High fixed cost Low variable cost

6,788

Variable Cost

Fixed Cost

1,158

Generation Cost Luzon Demand Profile (2013)

Generation Cost Matching Demand with Base-load, Mid-Merit & Peaking Generation

Peaking (1,043 MW) Mid-Merit (1,844 MW) Base-load (5,350 MW)

The Market Framework Uniform Price Auction SUPPLIER Those willing to sell at a lower price get to sell first

BUYER Those willing to buy at a higher price get to buy first

Price The market framework seeks short-run efficiency: Output is produced by least-cost suppliers Output is consumed by those most willing to pay The right quantity is produced •

•

No more sellers willing to sell at a lower price

Supply

 All Suppliers are paid at the same rate (i.e., a “ Uniform Price” which is the Clearing Price), notwithstanding their bid may be lower 

Clearing Price

•

No more buyers willing to pay a higher price

Demand

Quantity

The Market Framework The current market framework: demand is “Price-Taker”

SUPPLIER Those willing to sell at a lower price get to sell first

BUYER Buyers do not submit “demand bids”; they’re Price-Takers

Price

Clearing Price

Demand is Price Taker

Quantity

The Market Framework Market Power & Price Cap

• •

SUPPLIER MARKET POWER Physical (Capacity) Withholding Economic Withholding

Clearing Price With Market Power by Suppliers

Price

Market Price Cap Economic Withholding

Clearing Price Physical Withholding

Demand is Price Taker

Market Power

Quantity

The Market Framework Market Power, Price Cap & Demand Bid

• •

SUPPLIER MARKET POWER Physical (Capacity) Withholding Economic Withholding

Clearing Price With Market Power by Suppliers

Price Demand with response Market Price Cap

Clearing Price

Clearing Price

With Demand response

Demand is Price Taker

Market Power

Quantity

The Market Framework Market Power, Price Cap & Demand Bid

• •

SUPPLIER MARKET POWER Physical (Capacity) Withholding Demand with Economic Withholding limited response Price

Clearing Price With Market Power by Suppliers

Clearing Price With limited Demand response

Market Price Cap

Clearing Price

Demand is Price Taker

Market Power

Quantity

The Market Framework •

•

•

The overall objective of power systems operation is to produce power at the lowest total cost Uniform Price Auction promotes economic dispatch because of the financial incentives for the suppliers to bid their short-run marginal cost The market framework seeks short-run efficiency: •

•

•

•

Output is produced by least-cost suppliers Output is consumed by those most willing to pay The right quantity is produced

Generators win market share by offering low prices (Generators are more likely to bid at their marginal cost)

•

Demand is currently a “Price-Taker”

•

There are rules to thwart and prevent generators from exercising market power:

•

•

“Must Offer Rule” → physical withholding

•

“Price Cap” → economic withholding

•

“Secondary Price Cap” → “too-high-too-long”

The spot market operates under WESM Rules (approved by ERC)

The Market Framework WESM is the default market for sellers and buyers

•

Default market position: A Generator sells all its production in the WESM and a Customer (DU) buys all its requirements in the WESM, unless, they have a bilateral contract and their transaction is settled outside the WESM

•

•

•

RCOA effectively places Contestable Customers in the WESM (whose connection is conveyed through its DWSA) WESM prices are volatile Month to month, hour to hour changes More volatile than commodity prices (coal, oil, Fx) The business of entities selling and buying in the WESM are exposed to volatility risk (Not a way to run business!) • •

•

•

A bilateral contract is basically a hedge benefitting both buyers and sellers with business stability. WESM Rules on net settlement allow the parties to settle their bilateral contract transaction outside of the market In a WESM regime, the merit of a particular bilateral contract lies in: the “trade off” between: (a) the generation rate volatility indexed on commodity prices and escalation indices, versus (b) the WESM price volatility from market forces and chance events; Its competitiveness in relation to other offers (such as plants of other fuel types) •

•

The Market Framework End-User Protection

Generating Plant(s) Dominant Firm(s)

EPIRA Sec 43 (t) – Public Offering: Public offering of 15% of stock  EPIRA Sec 45 (a) - Grid Caps: 30% of grid  25% of national 

EPIRA Sec28 – De-Monopolization and Shareholding Dispersal

•

Pivotal Plant(s) PEMC Market Surveillance

Price Setting Plant(s)

•

EPIRA Sec 45 (b) - DU contract limit: 50% supply limit from associated  firm

End-User Distribution

Clearing Plant(s)

Transmission Bilateral Contract Supply

Must Offer Rule

Spot Market WESM Rules

ERC Tariff Regulation: Performance-Based Rate-Setting ERC Approval of DU PSA Regulation of Retail Rate

Market Suspension by ERC Natural Calamities National or international • •

The WESM WESM System has marked its 8 th year Highlights Luzon

•

The WESM is a real time, bid-based and hourly market for energy.

•

Similar designs: New Zealand, Australia and Norway.

Legend: WESM Connected Non WESM

Masinloc ►

•

Metro Manila

HVDC line & submarine cable

Luzon and Visayas grids run as a single market (88% of total demand) but with limited trade from weak interconnections (Leyte –Luzon HVDC 346 MW)

•

Metro Manila account for 59% of the consumption.

•

Annual peak demand occurs between May and June (Dry Season)

•

Three peaks occurring at 11:00AM, 2:00PM and 7:00PM.

•

Hourly trading intervals (shorter durations in the future)

Visayas

PARTICIPANTS Mindanao Mindanao

Luzon Direct

Visayas

Indirect

Direct

Generators

34

Electric Cooperatives

26

17

26

Private DUs

7

3

3

Bulk Users

6

49

7

Indirect

18 2

13

The WESM Operational Features



Mandatory Market: 







No one is allowed to inject to or withdraw  from the grid unless such entity is a WESM member  Generators must offer all its capacity (“Must Offer Rule”) Generators must run at Pmin (bid price zero)

Gross Pool & Central Dispatch: 



Generators must bid to win a market share regardless of their supply contracts; Taking into account system status, Market Operator (MO) schedules all available generation offers which are “stacked” from lowest to highest price until demand is met



Locational Market Pricing: 

The WESM price is the offer of the last “block” to be “stacked” to meet the demand 





A price is computed at each node reflecting the cost of transmission loss or congestion.

Net Settlement: 





Parties with bilateral contracts settle their transactions outside the WESM (paying their counter-parties directly based on contract  prices) Any off-take of a DU from the grid not matched with a generator’s BCQ declaration is deemed supplied from the market (the “spot quantity” for which DU pays the WESM) Settlements are essentially based on BCQ declarations

The WESM Sequence of Transactions BUYER Period ahead

Nominates day-ahead (or periodahead)requirements to itsPSA counter-party

SELLER

MARKET OPERATOR

Submits its offers before bid closing based on its customer nominations and its market strategy. Determines the settlement prices and Merit Order Table of how plants will be dispatched using the Market Dispatch Optimization Model (MDOM); sends to SO

1 hour before

Draws its real time requirements from the grid

Implements the dispatch schedule MOT and monitors actual system conditions and plant compliance with dispatch orders; makes real time adjustments for frequency, voltage and contingencies

Complies with SO instructions (tolerance of +/- 3%)

Trading interval (one hour)

Day after and Period after

SYSTEM OPERATOR

Declares to the MO the BCQs for its customers

Determines settlement information (counter-party quantities for BCQ, spot sales,); bills users and pays generators

SO provides actual metering data for previous day trading intervals

The WESM Gross Pool & Central Dispatch

Types of Offers/Bids

Generator Offer Rules •

Must offer all capacity (Pmax) all the time

•

Must offer Pmin at price of zero

•

Must make 10 offer blocks every interval for each unit (including Pmin as first offer block);

•

Minimum of 1 MW per block 

•

Block offers in ascending order of prices

•

Price cap at PhP 32,000/MWh



Standing Offers/Bids are default offers/bids that are submitted to ensure relevant data are used if the Trading Participant fail to submit Regular Offers/Bids



Regular Offers/Bids 

are offers/bids the Trading Participants submit hourly, daily, or any interval (maximum of 7 days) depending on the Trading Participants’ choice or strategy.



Also called Daily Offers/Bids as these are usually submitted on a daily basis.



A daily bid can only be submitted during an ‘Open Market Window’

The WESM Market Clearing Price

P 3,100/MWh

•

•

CLEARING PRICE Generators submit a bid for the energy they wish to supply Offers are arranged from lowest to highest price (“stacked”)

P 2,150/MWh

•

100

P 1,850/MWh

Gen F

P 1,350/MWh

100

P 900/MWh P 500/MWh

100

75

125 Gen C

Gne B

Gen A

Demand = 500 MW

200

Offer of last plant needed to meet demand sets the “Clearing Price”

•

Gen E

Gen D •

All Buyers pay at the Clearing Price All Generators are paid at the Clearing Price (whatever the offer)

The WESM Gross Pool & Central Dispatch

Plant Bauang

Fuel

Bid

Pmax

Pmin

Net of Pmin

8,500

190

Limay

Oil

12,000

540

Subic

Oil

9,000

120

Mariveles

Coal

1,800

600

300

300

Masinloc

Coal

1,300

600

160

440

Sual

Coal

1,400

1,200

450

750



Pagbilao

Coal

1,450

760

240

520



Quezon

Coal

1,375

456

180

276

MakBan

Geothermal

1,800

120

50

70

BacMan

Geothermal

2,000

130

55

75

Tiwi

Geothermal

1,500

100

40

Pantabangan

Hydro

1,200

130

130

Magat

Hydro

2,000

360

360

 

-

190

For a System Demand of 7200 MW, determine the following: 1. Market Clearing Price 2. Marginal Plant

Oil

540 120

60

Kalayaan

Hydro

2,100

740

Ilijan

Nat Gas

 

4,500

1,200

800

400

Santa Rita

Nat Gas

 

5,000

1,060

600

460

San Lorenzo

Nat Gas

5,000

530  

System Demand

7200

740

8,836

 

400

130

3,275

5,561

Given: No Non-Scheduled Generator No Must Run Unit (MRU)

The WESM Gross Pool & Central Dispatch

1 Plant

Fuel

Bids are sorted from lowest to highest

Bid

Pmax

Pmin

Net of Pmin

"Stack"

Limay

Oil

12,000

540

 

540

8,836

Subic

Oil

9,000

120

 

120

8,296

Bauang

Oil

8,500

190

-

 

190

8,176

Santa Rita

Nat Gas

San Lorenzo

Nat Gas

Ilijan

Nat Gas

   

5,000

1,060

600

 

460

7,986

5,000

530

400

 

130

7,526

4,500

1,200

800

 

400

7,396 Clearing Plant

 

740

6,996

 

75

6,256

 

360

6,181

Kalayaan

Hydro

2,100

740

BacMan

Geothermal

2,000

130

Magat

Hydro

2,000

360

55

Mariveles

Coal

1,800

600

300

 

300

5,821

MakBan

Geothermal

1,800

120

50

 

70

5,521

Tiwi

Geothermal

1,500

100

40

 

60

5,451

Pagbilao

Coal

Sual

Coal

1,450

760

240

 

520

5,391

1,400

1,200

450

 

750

4,871

Quezon

Coal

1,375

456

180

 

276

4,121

Masinloc

Coal

1,300

600

160

 

440

3,845

Pantabangan

Hydro

1,200

130

 

130

3,405

 

  System Demand

7200

The “Pmin” is

8,836

3,275

4 •

The last plant to be stacked to fully cover demand is the “Clearing Plant”; its bid sets the Market

Clearing Price

3,275

Non-Scheduled Generation

-

Must-Run Units

-

•

The “Pmin” is stacked at the

bottom (priced at zero)

The WESM Gross Pool & Central Dispatch

System Capacity = 8,836 MW

    h    W    M     /    P    n    i    s     d    i    B

System Demand = 7,200 MW

Market Clearing Price= P 4,500/MWh

Pmin = 3,275 MW

The WESM Gross Pool & Central Dispatch

Offers Not Dispatched

Offers Dispatched

The WESM Plant Dispatch Protocol: Planned Dispatch (Ex Ante)

Target Quantity

Initial Quantity

MO

RTD Schedule (what should happen) Interval 7 MMS – Market Management System MO – Market Operator EAQ  – Ex-Ante Quantity

0600H

0700H

The WESM Plant Dispatch Protocol: Intra-hour Redispatch

SO

Redispatch (SO Instructions) Interval 7 MMS – Market Management System MO – Market Operator EAQ  – Ex-Ante Quantity

0600H

0700H

The WESM Plant Dispatch Protocol: Actual(Ex Post)

Target Quantity

Initial Quantity

MO

RTX Schedule (What actually happened) Interval 7 MMS – Market Management System MO – Market Operator EAQ  – Ex-Ante Quantity

0600H

0700H

The WESM Settlement: WESM Transaction Amounts

Amount Settled in WESM

Amount Settled Outside WESM EPP

Amount Settled In WESM

EAP

Ex Ante Transaction Amount  “Imbalance” 

Amount Settled Outside of WESM (paid directly to generator)

EATA = EAP x (EAQ  – BCQ) Ex Post Transaction Amount  “Forecast Error” 

 Amount paid under PSA = BCQ x Contract Rate

EPTA = EPP x (MQ – EAQ)

BCQ EAQ

The WESM Determining the Ex Ante Price

Pricing Conditions

•

•

•

Price for Ex Ante

RTD

RTX

OK

OK

RTD

PEN

OK

RTX

OK

PEN

RTD

PEN

PEN

MRR

PSM

OK

PSMRTD

OK

PSM

RTD

PSM

PSM

PSMRTD

PSM – with congestion resulting in price separation by a factor of 1.2 or more (ratio of highest nodal price to lowest nodal price) PEN – with CVCs; with congestion (no large price separation) MRR – Market Re-Run, If the Ex-Post price is believed to be in error or reflect CVC prices

The WESM Determining the Ex Ante Price

The WESM NODAL PRICING: Understanding Line Rental



Line Rental – “The economic rental arising from the use of a transmission line, calculated as the difference in value between flows out of the receiving node of that line and flows into the sending node…”



Line rental charges pay for system loss and congestion costs incurred for quantities supplied through power supply contracts. Sending Node

Receiving Node BCQ →

Load

G1 Line Rental = BCQ x (LMPReceiving - LMPSending) 

Parties to a bilateral contract settle their transactions outside the market



A Generator will supply not only the energy for the BCQ of its customer but also to cover line losses



“Line rental” is a mechanism that allows a Generator’s recovery of its cost for suppling energy for line losses

The WESM Nodal Pricing: Line Rental from Transmission Losses Price G2 > Price G1

G2

Sending Node

100 MW

0 MWh

G1 200 MW

100 MWh + 5 MWh

Receiving Node

Transmission Capacity = 200 MW  Transmission loss = 5%

Transmission Loss = 5 MWh

Load 100 MWh



Because of “Transmission Losses”, a Generator’s delivery to the grid would be higher



than the energy received by the Customer Line rental compensates Generator for having to deliver more for transmission losses

The WESM Nodal Pricing: Line Rental from Congestion Price G2 > Price G1 Sending Node

G1 200 MW

80 MWh

 

G2 100 MW

24 MWh Transmission Capacity = 200 MW but subsequently restricted to 80 MW  Transmission loss = 5%

Transmission Loss = 4 MWh

Receiving Node

Load 100 MWh

When transmission limitations occur, the SO may be constrained to re-dispatch a more expensive Generator Line rental also compensates for the additional cost from a higher priced Generator to maintain load supply

The WESM Nodal Pricing: Line Rental from Transmission Losses 100 MWh + 5 MWh Offer:P 4000/MWh

0 MWh Offer: P 5000/MWh

Sending Node

G2

Receiving Node

100 MW

Transmission Loss = 5 MWh

G1

Load

Transmission Capacity = 200 MW  Transmission loss = 5%

200 MW

LMPG = P 4000/MWh

Load does not have PSA Trading Amount: Generator = 105 MW x P 4000/MWh = P420,000

Trading Amount: Load = TA + LR = 100 MWh x P 4200/MWh + 0 MW x P 200/MWh = P420,000

Settlement outside WESM = P 0.00

= P 0.00

Settlement outside WESM

100 MWh

LMPL = P 4200/MWh (= 4000 * 105/100)

Load has 100 MW PSA Trading Amount: Generator = (105-100)MWh x P 4000/MWh = P 20,000

Trading Amount: Load = TA + LR = 0 MWh x P 4200/MWh + 100 M W x P 200/MWh = P 20,000

Settlement outside WESM = 100 MWh x PSA Price

Settlement outside WESM = 100 MWh x PSA Price

The WESM Actual Operations: The spot market is volatile

The WESM Actual Operations: Lack of mid-merit plants in supply stack gestates volatility

$/MWh Stack Heirarchy

450

Peak Demand

Ave. Off-Peak Demand

2014 Peak Demand (8,717 MW)

Avg. peak demand 400 350

Avg. Off-peak demand

300 250 200 150 100

Pmin, Price Taker (Zero Bids) and MRU

50 0 0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

* Hydrology assumed at 30% capacity factor  ** YTD peak demand for 2014 is 8,717 (5.2% growth vs 2013)

Range of daily dispatch

9,000

10,000

The WESM Actual Operations: The market is highly contracted. Market Transaction Mix - stacked column

Market Transaction Mix - 100% stacked column

The WESM Actual Operations: Market Concentration Index - Herfindahl-Hirschman Index

Herfindahl-Hirschman Index (2010-2013)

The WESM Actual Operations: Market Concentration Index - Residual Supply Index Hourly Market Residual Supply Index Based on Offered Capacity of Generators (2010-2013) 250

200

150

100

RSI < 100% 50

0 1/1/2010

Presence of  Pivotal Generator(s) 5/31/2010

10/28/2010

3/27/2011

8/24/2011

1/21/2012

6/19/2012

11/16/2012

4/15/2013

9/12/2013

Monthly Market Residual Supply Index Based on Offered Capacity of Generators (2010-2013)

A Market RSI less than 100% indicates the presence of pivotal generator(s) in a period. A generator that frequently sets the price may have greater opportunities to design bidding strategies to influence the prices

The WESM Actual Operations: Market Concentration Index -Price Setting Frequency Index Price Setting Frequency Index (2013) Plants / Resource ID LUZON AMBUKLAO HEP ANGAT HEP APEC BAKUN HEP BATANGAS CFTPP BAUANG DPP BINGA HEP CASECNAN CBK (KPSPP) HEDCOR KEPCO ILIJAN LIMAY CCGT MAGAT HEP MAKBAN GPP MALAYA TPP MASINLOC CFTPP GN POWER MASIWAY HEP PAGBILAO CFTPP PANTABANGAN HEP QUEZON POWER SAN ROQUE POWER STA RITA FGPP SUAL CFTPP SUBIC POWER CORP

Category Below 5,000 5,000 to 10,000 Above 10,000 6.2%

12.1%

4.1%

2.2%

0.0%

0.1%

6.1%

0.0%

0.0%

0.2%

0.0%

0.0%

0.0%

0.0%

0.0% 50.3%

0.0%

27.5%

1.9%

2.3%

2.2%

1.8%

0.0%

0.0%

2.2%

1.6%

1.3%

2.2%

0.0%

0.0%

12.9%

0.0%

0.1%

1.0%

0.3%

14.0%

2.3%

5.9%

2.3%

4.4%

0.0%

0.2%

0.4%

0.0%

5.1%

26.8%

0.1%

0.0%

12.6%

0.1%

0.1%

1.2%

0.0%

0.0%

42.1%

0.5%

0.2%

0.5%

0.0%

0.0%

4.5%

0.0%

0.0%

1.8%

0.0%

0.1%

2.7%

0.1%

0.0%

40.5%

0.1%

0.0%

0.1%

25.9%

3.0%

The price setting index identifies the generators that set the price or are near setting the spot price in a trading interval. A generator is considered a price setter if its last accepted offer is within 95% to 100% of the nodal price. The PSFI is calculated as the percentage of time that a generator qualifies as price set

% of Time of Price Range (P) Occurance P < 5,000 5,000 < P < 10,000

12.3%

P > 10,000

12.4%

75.4%

The WESM Actual Operations: LWAP Analysis

The WESM The Reserve Market

Capacity in Outage Excess Capacity

NORMAL STATE

Next largest unit 

Dispatchable Reserve

Sufficient Operating Margin Within limits for frequency, voltage, transmission loading

•

Capacity

Largest unit 

•

Contingency Reserve 4% of Demand 

Regulating Reserve

Energy

Plants in Merit Order Table dispatched for energy

 S   y   s   t    e  m D   e  m  a  n  d 

YELLOW ALERT  A   v   a  i    l    a  b   l    e  C   a  p  a  c   i    t    y 

•

RED ALERT • •

• •

Contingency Reserve is zero Generation deficiency exists There is Critical Loading Imminent overloading of Trans. Line or equipment

Contingency Reserve is less than capacity of largest synchronized unit

 S   y   s   t    e  m  C   a  p  a  c   i    t    y 

The WESM The Reserve Market Rationale for the Reserve Market •

•

•

•

Widen competition and supply base for Energy and Reserves Lower overall cost from Co-optimization of Energy and Reserves Transparency in pricing and dispatch scheduling Incentive for new generation investment and customers with dispatchable (interruptible) loads

ENERGY MARKET

Scheduling

Pricing

Settlement

Gross Pool Concept

Locational Marginal Price

Ex Ante & Ex Post Settlement

WESM Rules 3.5.5

RESERVE MARKET

Gross Pool Concept

WESM Rules 3.5.7

WESM Rules 3.5

WESM Rules 3.10.1

Zonal Reserve Price

Ex Ante Pricing Settlement

WESM Rules 3.10.10

WESM Rules 3.10.10



Energy and Reserve Co-optimization (WESM Rules 3.6.1.1 ) Simultaneous determination of schedules and prices 



Other Markets with Energy and Reserve Co-Optimization Singapore  New Zealand    Australia (AEMO)  US (PJM, CAISO, NYISO, MISO)  Canada (IESO)

The WESM Price & Cost Recovery Mechanism for the Reserves Market

•

The application for the approval of the PCRM was filed with the ERC on Jan 8, 2007;

•

On Jul 7, 2008, the ERC also directed compliance to directives: •

• •

Approved by the ERC on Jul 7, 2008:

Realign Specifications of Reserve Services to create a Fast Contingency Service

•

Gross Pool concept

•

•

Zonal reserve pricing

•

•

Ex-ante settlement

•

Co-optimization of energy and reserves

•

Set up interim arrangement for ILD

•

Administered reserve prices

•

Set up appropriate changes in the Phili ppine Grid Code

•

•

Implement an Ex-Ante Reserve Effectiveness Factor

Re-filed with the ERC on Feb 26, 2013; hearing by ERC on Jan 28, 2014. PEMC recommends 2-stage implementation: •

Interim Phase (Mar 26, 2014): Operate Reserve Market

based on current design •

Completion Stage (24 Months after Interim Phase): Full

compliance to all ERC directives

•

Set up new Lower Reserve Service Introduce Interruptible Load Dropping (ILD) as a fully functioning reserve service

Submit plans for future enhancement and develop Interim Plans Establish appropriate mitigating measures in the Energy and Reserve Market to curb misuse of market power or occurrence of anti-competitive behavior

The WESM Market Dispatch Optimization Model (Co-optimization) Sequential Clearing GENERATOR

Energy

Results in more expensive marginal price of P 12,000/MWh for energy

GENERATOR Pmax, MW

Energy Offer, P/MWh

Quantity, MW -

-

Reserve

400

-

B

200

100

C

150

100

D

50 Total

400

B

300

3, 000. 00

100

1 ,000. 00

C

250

5, 000. 00

250

4 ,000. 00

D

300

12, 000. 00

300

7 ,000. 00

C

D

Maximized for reserves 4000

Reserve (200 MW)

1000

-

800

200

   0    0    0    0    7

Energy only 5000 3000

9,600 K 800 K 10,400 K

3000

Remaining scheduled for energy

Price, P/MWh

A

B Maximized for reserves

A

Total Cost 800 MW x 12 K = 200 MW x 4 K = Total

Reserve Offer

A

Schedules, MW

Balance for energy

Balance of Energy requirement

Energy (800 MW)

-

Simultaneous Clearing Schedules, MW GENERATOR Energy A

Requirement: Energy = 800 MW Reserve = 200 MW

-

B

200

100

C

200

50

D

Total

Co-optimized solution dispatches a more expensive resource for reserve (P 7000/MWh) Overall cost is lower as a result of cheaper marginal energy price of P

Reserve

400

Total Cost 800 MW x 5 K = 200 MW x 7 K = Total

800

A

B

C    0    0    0    4

1000

50

D

Backed off for reserves

Maximized for reserves

   0    0    0    7

Reserve (200 MW)

200

4,000 K 1,400 K 5,400 K

Balance of reserve requirement

Energy only 5000 3000

Remaining scheduled for

5000

3000

So that more can be provided for

Energy (800 MW)

The WESM Energy and Reserve Market Co-optimization

Reserve Price in the WESM 

A reserve region shall have only one market price per type of reserve per trading interval  Regulating,  Contingency,  Dispatchable, and  Interruptible load).



The market price shall be the zonal reserve price

Zonal Reserve Price = Reserve Clearing Price + Opportunity Cost 

Clearing Price is the reserve offer price of the last resource to satisfy the reserve requirement plus the concept of opportunity cost.



Opportunity Cost is defined as the economic loss suffered by generating resource from losing an opportunity to sell in the energy market as a result of being scheduled in the reserve market