7. Opportunities for Cogeneration in the Alberta Electricity Market - Gopi

5/19/2018 7. Opportunities for Cogeneration in the Alberta Electricity Market - Gopi

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Opportunities for Cogeneration in theAlberta Electricity Market

Biju Gopi

Manager, Commercial Services

Alberta Electric System Operator (AESO)


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Scope of Presentation

AESO Overview 2011 Annual Market Statistics

Ancillary Services Market in Alberta

2012 Long-term Outlook (Forecast)

2


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AESO Overview

3


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Albertas Electricity System

26,000 km of transmission lines

Single control area of 660,000 km

B.C. & Saskatchewan interties

164 market participants

Over 258 generating units

13,939 MW installed capacity

6263 coal MW

5538 gas MW

879 hydro MW

861 wind MW

10,609 MW system peak (January

16, 2012) and 82% average load

factor


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Electr ic Uti l i t ies A ct

Minister of Energy

Appoints Board members & MSA

MarketSurveillance

Administrator

BalancingPool

Wholesale

Energy

Market

Transmission

Planning

Alberta ElectricSystem Operator

Real-time

Operation of

Electric System

AUC

Load

Settlement

Alberta Industry Structure

Alber ta Uti l i ties Comm iss ionAct

CabinetAppoints Commission

Members and Chair of AUC

ComplianceSurveillance

Consumer

Financial accts

PPA Obligations


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Long-term Objectives of ourWholesale Market

Long-term stability and competitively priced electricity to Albertans

Signals that are predictable and understandable; supportinvestment in the electricity sector and provide a foundation foreconomic growth

Suppliers need confidence they can move their product tomarket and have the opportunity to compete

Load must be assured it will have access to needed electricsupply in a predictable fashion and at a price reflective ofmarket fundamentals

A competitive wholesale market for energy coupled with anunconstrained transmission system deliver a long-term supply ofneeded electricity without government contracts or public debt

No central planning of generation; investors make decisions and

take risk on type, timing and location of investment6


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Alberta Energy Market Overview

Energy-only market design

Founded on the premise of a congestion freetransmission system

ISO Rules govern market activity

Generator participation is mandatorymustoffer, must comply

164 market participants

High industrial load

Small market with limited interconnections

~$8 billion (2011) in annual energytransactions

$1,000/MWh price cap and $0/MWh price floor

Load is passive participant

Cost of operating market recovered through

energy trading charge


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0

20

40

60

80

100

0 2000 4000 6000 8000 10000 12000

Price($/M

Wh)

pp

Hourly Power (MW)

Energy Only Real-time Market

Price is set where supply = demand, in real time

6,000 MW7,000 MW offer in at $0

cogeneration, hydro, baseload coal, wind8

Supply

Demand(peak)Demand

(off-peak)

Peak Price =$50

Off-peak Price =$35

8


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Offers and Bids

AESO accepts offers to sell power and bids to buy power throughthe Energy Trading System (ETS)

Generators Must Offer, Must Comply

The merit order is created by ordering the least priced offers to thehighest priced ($0 - $999.99/MWh)

The merit order is dispatched by the system operator as often as isnecessary to maintain supply demand balance on the Alberta grid

SettlementInterval

T-2 to TGate Close (Noon of the previous day) to T-27 Days ahead

Enter Offers (Price-

quantity pairs, available

capacity)

Able to change price-

quantity pairs, can

change available capacity

with an acceptable reason

Cannot change prices, can change

quantity offered at the prices in the

offer with an acceptable reason, can

change available capacity with and

acceptable reason.


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0

2,000

4,000

6,000

8,000

10,000

12,000

14,000

1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011YTD

MW

Installed Generation 1998-2011

WindOther

Hydro

Cogen

Gas

Coal

Peak Load

Average Load

10

Growth in Supply

861 MW of wind(6.3% of installedcapacity) andexpected to bearound 1100 MW byend of 2012

Over 6,400 MW of newgeneration have been added

since 1998 financial risk taken

by the generation builders

supporting more than 2,400 MW

of average load growth

10


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Energy Consumption is Separated IntoCustomer Sectors for Analysis

Customer Sector Electricity Consumption

2011 Total Consumption = 69,495 GWh

Oilsands

17%

Commercial

20%

Residential

13%

Industrial (without

Oilsands)

47%

Farm

3%

Source: ERCB, AESO 11


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Brattle ReportSustainability of Albertas Electricity Market

Generation retirements and anticipated growth (annualized growth)will require investment in new capacity equivalent to what we haveseen since 1998 (over 5,000 MW capacity added) in the next 9years

Installed capacity is expected to increase from approximately

13,000 MW today to over 19,000 MW by 2020 Current market design is well-functioning and can support the

higher rate of generation additions, as long as large simultaneousretirements can be avoided

Projected market prices strongly favor a shift in the resourcemix from coal generation to natural gas-fired power plants,which are more flexible and have lower capital costs. As a result,we current ly see no compel ling need fo r major changes

in Albertas electricity market design

12


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2011 Annual Market Statistic Report

13


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2011 Annual Market Statistics

Released February 16, 2012

Summary of key market information

Describes historic trends inAlbertas wholesale electricity

market

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Pool Prices Increase in 2011

2011 annual average pool price was $76.22/MWh Gas prices stable

Market heat rate rose from 13.6 in 2010 to 22.4 GJ/MWh in 2011

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Revenue by Pool Price Range

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Continued Growth in Load

Total Alberta Internal Load grew 2.6% in 2011

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Imports Serve 5% of Total Load in 2011

Alberta has two interties: B.C. and Saskatchewan

Imports vary depending on intertie limitations, marketprices in other jurisdictions, and other factors

Total net imports increased 107% on the B.C. Intertie

and 60% on the Saskatchewan Intertie Alberta remains a net importer for the tenth year in a row

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Ancillary Services Market in Alberta

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What are Ancillary Services?

Electric Utilities Act definition

those services required to ensure that the interconnected

electric system is operated in a manner that provides a

satisfactory level of service with acceptable levels of voltage

and frequency

Includes Operating Reserve, Transmission Must-RunServices, Load Shed Services and Black Start Services

Cost recovered from loads through the ISO Tariff

Market participants sell ancillary services to the AESO Total annual cost of ancillary services ~ $371 million (2011)

projected 2012 costs are ~$333 million


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Contracted Ancillary Services

Black Start Services AESO procures through bi-lateral agreements

Currently there are 2 providers of this service (investigating ifmore are required)

Fixed price and call price

Load Shed Services

New LSSi service for importsto support higher electricity

import levels on AlbertaB.C. intertie Fixed Price for offering ($5/MWh)availability payment

Contract Price for armingarming payment

Trip Payment ($1000/MWh)trip payment


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Transmission Must-Run (TMR)

The AESO procures TMR services through bi-lateralagreements with generators

Where we can we run a competitive process for foreseen TMR,we will

Section 11 of the AESO tariff sets out the payment forconscripted TMR (unforeseen TMR)


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Operating Reserve Market

Market operated by a third party, Watt-Ex

AESO is a market participant, unlike the energy market

Participation is voluntary, unlike the energy market

Contracts govern market activity, not rules

OR prices are indexed to energy market pool price

Cost of OR are recovered from load through the ISO Tariff

Energy market participants supply OR

Total annual cost of OR ~ $ 329 million (2011)projected2012 costs at ~$253 million


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Types of Operating Reserve

Operating Reserve

RegulatingReserve

Generators

with AGC

Contingency Reserve

Spinning

Generatorssynchronized to the

grid

Supplemental

Generators orLoads

24


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OR Market Participation by CogenerationUnits

23 qualified participants in the OR market

59 units qualified to participate in 3 OR products (RR, SR,SUP)

10 cogeneration units qualified to provide reserves (17% of

qualified units) Of the qualified cogeneration units:

2 do not appear to be participating

1 only participates in Standby

1 only participates in Active


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Location of Cogeneration Units in Alberta


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Market Share

Cogeneration units are a substantial provider of StandbyReserve:

Regulating: 23%; Spinning: 31%; Supplemental: 14%

Cogen, Active RR, 20.6%Cogen, Active SR, 31.1%

Cogen, Active SUP, 6.8%

Cogen, Standby RR, 22.6% Cogen, Standby SR, 37.1%

Cogen, Standby SUP, 14.2%

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

RR SR SUP RR SR SUP

Active Standby

Operating Reserves Market Shares - 2011

Tie

Load

Hydro

GasCogen

Coal


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Behavior

Active Standby

RR SR SUP RR SR SUP

On PeakParticipates inSuper Peak Primary No on/off

differentiationPrimary Primary

Off Peak Primary Primary

Cogeneration units vary their type of participation in the ORmarket based on time of day, though there is no period inwhich cogeneration units do not provide OR

During Off Peak hours (HE 1-7, &4) cogeneration unitsprovide more Regulating Reserve than during On Peak (HE8-23)


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Observed OR Market Prices

RR is typically the premium product, with SR and the SUPfollowing in the order of price

Active prices are indexed to pool price, hence the strongassociation to the annual average price

ActiveStandby

premiumsStandby activation Total OR Cost

($ millions)

Average hourlypool price

($/MWh)RR SR SUP RR SR SUP RR SR SUP2007 $34 $29 $26 $5 $4 $4 $101 $101 $96 $185 $66.95

2008 $51 $43 $38 $7 $5 $5 $163 $151 $133 $270 $89.95

2009 $23 $16 $11 $5 $4 $3 $96 $85 $69 $104 $47.81

2010 $27 $21 $16 $7 $4 $4 $141 $115 $91 $137 $50.88

2011 $55 $57 $51 $6 $8 $7 $98 $121 $95 $328 $76.22


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2012 Long-term Outlook (Forecast)

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2012 Long-term Outlook

Updated forecast is a key input tothe Long-term Transmission Plan

Forecasts input into various AESOfunctions

Validated and improved ourprocess, models and inputs thiscycle

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Alb t F t t G F t th


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Canadian Forecast Economic Growth 2011-2030

2.1%

1.9%

2.5% 2.4%

2.1%

2.2%

1.5%1.3%

0.7%

1.4%

0.9%

0.0%

0.5%

1.0%

1.5%

2.0%

2.5%

3.0%

Canada BC AB SK MB ON QC NB NS PEI NL

AverageA

nnualGDPGrow

th(%)

Alberta Forecast to Grow Faster thanAnywhere Else in Canada

Source: Conference Board of Canada 32


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Alberta Crude Oil Production Forecast

0

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

4,500

2002

2003

2004

2005

2006

2007

2008

2009

2010

2011

2012

2013

2014

2015

2016

2017

2018

2019

2020

2021

2022

2023

2024

2025

2026

2027

2028

2029

2030

2031

2032

Prod

uction(thousand

bbl/d)

Non Oilsands Production Oilsands Production

Soaring Oilsands Production

Oilsands production is expected todouble over the next 10 years

Source: CAPP, Conference Board of Canada, AESO 33


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Regional ResultsFocus on Northeast

Fastest growing region in the province

Load driven by oilsands, increased loadintensity as sites mature, new reservoirsand technology

Cogeneration development driven byoilsands projects

Long-term potential for hydro & geothermal

2012 LTO (MW) Load Generation2011 actual 2,557 3,001

2022 forecast 4,506 5,188

A G th R t O N t 20 Y


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0

2,000

4,000

6,000

8,000

10,000

12,000

14,000

16,000

18,000

20,000

2002

2003

2004

2005

2006

2007

2008

2009

2010

2011

2012

2013

2014

2015

2016

2017

2018

2019

2020

2021

2022

2023

2024

2025

2026

2027

2028

2029

2030

2031

2032

PeakDemand(MW)

Alberta Internal Load (AIL) Peak Demand

Forecast

2012 LTO Historical35

Average Growth Rates Over Next 20 Years areIn Line with Historical Rates

3.5%

3.1%

2.4%

Average Annual Historical Growth Rates:

20-year (1991-2011): 3.0%10-year (2002-2011): 2.9%

5-year (2007-2011): 1.9%

L d G th d R ti t D i


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0

5,000

10,000

15,000

20,000

25,000

2011/2012

2012/2013

2013/2014

2014/2015

2015/2016

2016/2017

2017/2018

2018/2019

2019/2020

2020/2021

2021/2022

2022/2023

2023/2024

2024/2025

2025/2026

2026/2027

2027/2028

2028/2029

2029/2030

2030/2031

2031/2032

2032/2033

MW

Effective Existing Other

Effective Existing Wind

Existing Effective Hydro

Existing Gas

Existing Coal

Expected Effective Generation Capacity

Forecast Peak Demand (AIL)

5,700 MW 11,200 MW

36

Load Growth and Retirements DriveGeneration Additions

Retirements

Load growthwith margin

6,200 MW

11,900 MW

16 000 MW f G ti P j t


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37

16,000 MW of Generation ProjectsAnnounced for Alberta

Substantial generation

development in last ten years

Over 16,000 MW generationcapacity additions announcedfor Alberta

Indication of the strong

interest in developinggeneration in Albertas energy

only market

Forecast considers:

Planned projects

Generation economics

Policy implications

One-on-one consultation

Technology development

0

2000

4000

6000

8000

10000

12000

14000

16000

18000

Generation Capacity (MW)

OtherCoal-fired

Future Hydro

Cogeneration

Wind

Gas-fired

Announced Generation Capacity


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3838

Capacity expected to increase from 13,660 MW now to 19,555 MW in 2022

Sustained low gas prices and published coal legislation maintain outlook forgas-fired generation additions

Gas-fired combined cycle and cogeneration 2/3 of additions

2012 Long-term Generation Outlook

Existing Generation Mix 2022 Generation Mix

Coal-fired

(6242 MW)

46%

Cogeneration

(3782 MW)

28%

Combined

Cycle

(750 MW)

6%

Simple Cycle

(827 MW)

6%

Hydro

(879 MW)

6%

Wind

(865 MW)

6%

Other

(314 MW)

2%

Coal-fired

(4832 MW)

25%

Cogeneration

(5770 MW)

29%

Combined

Cycle

(3668 MW)

19%

Simple Cycle

(1176 MW)

6%

Hydro

(979 MW)

5%

Wind

(2544 MW)

13%

Other

(585 MW)

3%


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Key Takeaways

Economic growth in Alberta is expected to remain strong

Oilsands remains the economic growth engine for theprovince

Shift from coal-fired generation to gas-fired generation

following federal environmental policy and sustained gasprices

Generation capacity additions announced indicate a stronginterest in developing generation in Albertas energy only

market The Alberta electricity market continues to function effectively

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Some Useful AESO Links

Website: www.aeso.ca

AESO Market Policy Implementation:http://www.aeso.ca/market/8836.html

Ancillary Services Webpage:

http://www.aeso.ca/market/5093.html Ancillary Services Participant Manual:

http://www.aeso.ca/downloads/Ancillary_Services_Participant_Manual_Edition_3_January_2012.pdf

Ancillary Services Technical Requirements:http://www.aeso.ca/rulesprocedures/9108.html

2012 Long Term Outlook:http://www.aeso.ca/transmission/8638.html

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http://www.aeso.ca/http://www.aeso.ca/market/8836.htmlhttp://www.aeso.ca/market/5093.htmlhttp://www.aeso.ca/downloads/Ancillary_Services_Participant_Manual_Edition_3_January_2012.pdfhttp://www.aeso.ca/downloads/Ancillary_Services_Participant_Manual_Edition_3_January_2012.pdfhttp://www.aeso.ca/rulesprocedures/9108.htmlhttp://www.aeso.ca/transmission/8638.htmlhttp://www.aeso.ca/transmission/8638.htmlhttp://www.aeso.ca/transmission/8638.htmlhttp://www.aeso.ca/rulesprocedures/9108.htmlhttp://www.aeso.ca/rulesprocedures/9108.htmlhttp://www.aeso.ca/downloads/Ancillary_Services_Participant_Manual_Edition_3_January_2012.pdfhttp://www.aeso.ca/downloads/Ancillary_Services_Participant_Manual_Edition_3_January_2012.pdfhttp://www.aeso.ca/downloads/Ancillary_Services_Participant_Manual_Edition_3_January_2012.pdfhttp://www.aeso.ca/market/5093.htmlhttp://www.aeso.ca/market/5093.htmlhttp://www.aeso.ca/market/8836.htmlhttp://www.aeso.ca/market/8836.htmlhttp://www.aeso.ca/


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Contact Information

Biju Gopi

Commercial Services, AESO

2500, 3335th Ave SW, Calgary, AB, T2P 0L4

[email protected]

T: 403-539-2572

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mailto:[email protected]:[email protected]:[email protected]


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Thank you

Documents

7. Opportunities for Cogeneration in the Alberta Electricity Market - Gopi