impacts of the transition to a capacity market on the...

Impacts of the Transition to a Capacity Market on the Alberta Electricity Market

Allen Crowley, MBAEDC Associates Ltd.

403-648-0632 allen@edcAssociates.com

Prepared For

EDC Functional Work Areas

• Independent energy-consulting firm established in 1992• Regularly issues 6 news letters and reports to over 300

Alberta based market participants–most issued since 1997• Over 125 active clients• 8 full-time professionals• www.EDCAssociates.com

EDC

Energy Industry Training

Energy Price Forecasting

Generation Feasibility &

Value Analysis

Energy Procurement

& Management

Regulatory/Legal

Consulting

2EDC Associates Ltd.

Butterfly Effect1. Renewables Policy

– Accelerated Coal Retirements (2030)• Large Payouts to post-2030 Coal Units

– Increased Carbon Tax (Raises coal costs and government revenues)• Intensity: SGER to OBA: Base 0.37t/MWh, -1%/year)• Carbon Price: $30-$50/t

– Low Risk Incentives for 5,000 MW of Renewables (REP Costs) (Better Financing)– PPA Buyers Terminate Coal PPAs, then Balancing Pool Returns Units to Owners– What is considered renewable? Wind, Solar, Biomass, Hydro,…

• Cogen? Tie? Storage? EV?

2. Capacity Market Transition– Implementation by 2021, Replace “Energy Only” market with Capacity Market– EOM: Paid if Dispatched, Capacity Market: Paid if “Available” 2 revenue streams– Target reliability NEUE 0.0011% (Unserved Load/Total Load) ?– Round 1 REP Winners cannot participate, next rounds?– Net CONE of Reference Technology ( Simple Cycle?)– Possible Offer Behaviour Mitigation– Cost Allocation based on “Performance Hours” (Peak Load or Supply Cushion?)

3EDC Associates Ltd.

Long Term Effects (CLP&CM)– Incents New Generation to build in New Locations

• Extra Revenue Sources (REP, Capacity Payments) – Changes Pattern of Generator Dispatch

• Which generators, which load hours, which TRX lines, tariff base, cost allocations

• Changes Daily Pattern of Transmission Flows– Changes Who Makes Money and How

• REP• Capacity Payments• Lower Energy Revenues (Offer mitigation, more supply)

– Transmission and Overall Rate Shock– Encourages More Distribution Level Generation

4

TRANSITIONING TO A CAPACITY MARKET

6

Capacity Market• November 2016 Government of Alberta endorses capacity

market transition– Concern that increased renewable penetration would lead to significant

price volatility and deter dispatchable investment, impacting reliability• Target: first capacity auction in 2019 for 2021 delivery• 5 industry working groups consolidated to 3 in January 2018

Supply and Demand are Volatile

7

5,000

6,000

7,000

8,000

9,000

10,000

11,000

12,000

13,000

14,000

15,000

16,000

17,000

18,000

19,000

MW

Alberta Supply and Demand Balance

Forecast AIES SupplyPeak AIES DemandExisting Supply as of 2017, less cumulative retirements

9,562 MW of AIES Additions by 2031

2016 Min Demand5,449 MW (AIES)

2016 Max Demand9139 MW (AIES)

2016 Max Available13,075 MW

2016 Min Available7,794 MW

How Much Reserve is Needed

8

Maximum Surplus

ExpectedLoad

Target Shortfall : 800MWh/yearofLostLoad→

Variancefromtemperature,windspeed,daylighthours,workday,distributionoutages,DR,losses Available

Capacity

Normaloutages,

mothballing,TRXoutages

Coincident peak Supply

Baseload

Peak

* Illustrative only. Not necessarily to scale

Nameplate

Reserve Margin

Maximum Shortfall

Surplus

Seasonal derates, intermittence, TRX outages

Behind the fence load Behind the fence loadHighest Prices

Daily Load Profile by Month

EDC Associates Ltd. 9

EDC Associates Ltd. 10

•Predictable vs. Random Volatility

Demand is Predictable, Sort of

Capacity Market Swing Variables

• Choice of Reliability Level– LOLE, NEUE (Frequency, duration, magnitude)

• Carbon Stringency and Price Escalation– 0.37-0.3 t/MWh– $30-60/t

• REP MW In/Excluded from Capacity Auction• Net CONE Method• UCAP Method

– Peak Load Hours (1 CP, 12 CP, Top 100, 500)– Tightest Supply Cushion Hours (100 or 500)

• Amount of Coal-to-Gas Conversions – 0-6,000 MW

• Amount of Offer Behaviour Mitigation• Legislation Revised or Rescinded

11

Structure (Market Mechanics)

12

• Centralized market administered by the AESO• New assets offer at Net CONE• Existing assets likely offer at a fraction of Net CONE

(~fixed cost)• Obligations/procurement/auction will not vary based

on resource type or vintage• Likely financial incentives and penalties for

over/under performance during hours of system stress (Zero-sum or biased)

Price Setting

13

As coal retires simple-cycle becomes the marginal unit more often

0%

10%

20%

30%

40%

50%

60%

70%

80%

Price Setting by Generation Type Under 0.1 LOLE (2017-2031)

Coal Cogen Combined Cycle Simple Cycle Hydro Tie Biomass Wind Solar

CLP Changes Lower Merit Order

EDC Associates Ltd. 14

$0

$10

$20

$30

$40

$50

$60

$70

$80

$90

$100

2018 Merit Order ($0 to $100/MWh Offers)

SGER Merit Order Coal (SGER) Calgary Energy Centre (SGER)CLP Merit Order Coal (CLP) Calgary Energy Centre (SGER)

Increaseincarbontaxraisescoal'smarginalcostofferby$12-$15/MWh,whereascarbontaxforacombinedcyclegas-firedunit(assumedtosetintensitytarget)dropsto$0/MWh,droppingbelow coalinthemeritorder(atthecurrentgaspriceforecast).

CECBlock 1

CECBlock 2

CECBlock 3

GN1Block 1

GN1Block 2

Allowable Offer Behavior (Energy & AS)

15

$0

$100

$200

$300

$400

$500

$600

$700

$800

$900

$1,000

Offe

r Pric

e ($

/MW

h)

Sample Merit Order Compositions

Cost-Based Offers Opportunistic Offers Opportunistic Offers w/ $300 Cap

UCAP METHOD

How Much Capacity to Procure

17

0

2,000

4,000

6,000

8,000

10,000

12,000

14,000

16,000

18,000

20,000

22,000

24,000

26,000

28,000

MW

Gross & Non-REP UCAP Capacity

Gross Capacity AIES Capacity UCAP inc. REP Renewables UCAP w/o REP Renewables

Gross Fleet Capacity

UCAP Capacity Procured w/ REP Renewables

AIES Fleet Capacity

UCAP Capacity Procured w/o REP Renewables

Price vs. Supply Cushion (2015)

EDC Associates Ltd. 18

4,000

5,000

6,000

7,000

8,000

9,000

10,000

5,000 6,000 7,000 8,000 9,000 10,000 11,000 12,000

Dom

estic

AIE

S D

eman

d

Available Net-to-Grid Supply

2015 Supply vs Demand by Price Range

0-10

10-20

20-30

30-40

40-50

50-75

75-100

100-500

500-750

750-1000

Supply Cushion= 0500

3500

30002500

20001500

1000

4000

System Stress Happens Anytime (e.g., 2016)

19

1

2

3

4

5

6

7

8

9

10

11

12

Month

Supply Cushion (MW)

Distribution of Tight Supply Cushion (2013)Dec

Nov

Oct

Sep

Aug

Jul

Jun

May

Apr

Mar

Feb

Jan

68Hr

108Hr

185Hr

269Hr

366Hr

530Hr

747Hr

1092Hr

1537Hr

1977Hr

2528Hr

3044Hr

Coal/CCGT UCAP is 10% Higher using Peak Load vs. Tightest Supply Cushion

20

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

Aver

age

UC

AP R

atin

g D

urin

g M

easu

rem

ent P

erio

d (%

)

Avg. Coal UCAP Rating During Measurement Periods

100 Tightest Supply Hours 100 Top Load Hours

UCAP Based on Peak Load is 15% Points Higher than UCAP Using Supply Cushion (South: 2-3X)

21

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

Aver

age

UC

AP R

atin

g D

urin

g M

easu

rem

ent P

erio

d (%

)

Average Wind UCAP Rating During Measurement Periods

100 Tightest Supply Hours 100 Top Load Hours

NorthernUnits SouthernUnits

Wind and Solar both Seasonal

EDC Associates Ltd. 22

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

Capa

city

Fac

tor (

%)

Quarter-over-Quarter Heat Rate Forecast Comparison

Wind Solar

EDC Associates Ltd. 23

Wind Never Runs at Full Nameplate

Wind Discount

24

-75%

-50%

-25%

0%

25%

50%

75%

100%

125%

150%

175%

-$75

-$50

-$25

$0

$25

$50

$75

$100

$125

$150

$175

(Dis

coun

t) / P

rem

ium

to P

ool P

rice

(%)

Pric

e ($

/MW

h)

Pool Price, Wind Average Received Price & Discount to Pool Price (Jan 2009 - Sep 2017)

Pool Price Average Received Price Discount Average Discount (-22%)

2009 201220112010 2013 2014 2015 2016 2017

Wind discount has shrunk while prices are low

% of $0/MWh Hours

25

Unlikely to be a problem at 5,000 MW and NEUE = 0.0011%

0.0%

0.5%

1.0%

1.5%

2.0%

2.5%

3.0%

3.5%

4.0%

4.5%

5.0%

% of Hours Settled at $0/MWh

NET CONE CALCULATION

Net CONE Calculation (Reference Unit)

27

Debt Interest

Return on Equity

Weighted Cost of Capital

Tax Rate

Life

Capi

tal C

ost

Gros

s CON

E (Y

early

Req

uire

d Fix

ed R

even

ue)

F&V

O&M

G&A

Varia

ble

Non-

Fuel

O&

M

Fuel

Cos

ts

MW

h*Ga

s Pric

e* H

R

One Year’s Amortization

One Year’s Levelized Return

on Capital

One Year’s Levelized Capital

Recovery

Net

CONE

Ener

gy a

nd A

S Re

venu

e

E &

AS

Mar

gin

O/S Capital

(minus)

Net CONE

28

• Very Sensitive to Allowable Offer Behavior• Energy and capacity revenue streams move opposite of each other

$0

$100

$200

$300

$400

$500

$600

$700

$/M

W-D

ay

Cost of Capacity ($/MW-Day)

Marginal Cost Opportunistic Offers

COAL-TO-GAS CONVERSIONS

Evolution of Gross Output

30

Coal retires, replaced with coal-to-gas, combined-cycle, simple-cycle, wind

0

20,000

40,000

60,000

80,000

100,000

120,000

GW

h

0.1 LOLE: Alberta's Gross Generation w/ Coal-to-Gas Conversion

Coal Cogen Combined Cycle Simple Cycle Coal to Gas Hydro Tie Biomass Wind Solar

Coal-to Gas Uses up New Room

31

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

Rem

aini

ng C

oal C

apac

ity a

t Yea

r End

(MW

)

Remaining Coal Capacity at Year-End (MW)

Original Federal 2030 Maximum (Cliff)Partial Coal-to-Gas Partial Coal-to-Gas + Remaining CoalFull Coal-to-Gas Full Coal-to-Gas + Remaining Coal

6,500 MW vs. 1,500 MW w Full C-t-G

32

0

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

4,500

5,000

5,500

6,000

6,500

7,000

7,500

MW

Thermal Developed Between 2020 and 2031

No Coal-to-Gas (All) Partial Coal-to-Gas (All)Partial Coal-to-Gas (CCGT, SC, CGN) Full Coal-to-Gas (All)Full Coal-to-Gas (CCGT, SC, CGN)

High Marginal Cost of C-t-G

33

$0

$10

$20

$30

$40

$50

$60

$70

$80

$/M

Wh

Fuel GHG Variable

2020

20252030

Cost of Capacity Falls with C-t-G

34

$0

$1,000,000,000

$2,000,000,000

$3,000,000,000

$4,000,000,000

$5,000,000,000

$6,000,000,000

$7,000,000,000

$8,000,000,000

$9,000,000,000

$10,000,000,000Cumulative Cost of Capacity ($)

0.0011% NEUE, Offers, Partial CTG, Tight 500 SC 0.0011% NEUE, Offers, Full CTG, Tight 500 SC

0.0011% NEUE, Offers, No CTG, Top 500 Demand

C-t-G Raises Pool Price, Lowers Capacity Cost

35

$0

$10

$20

$30

$40

$50

$60

$70

$80

$90

$/M

Wh

Pool Price ($/MWh)

0.0011% NEUE, Offers, Partial CTG, Tight 500 SC 0.0011% NEUE, Offers, Full CTG, Tight 500 SC

0.0011% NEUE, Offers, No CTG, Top 500 Demand

LOAD FORECAST DRIVERS

AESO LTO

37

• AESO collapsed load forecast in last LTO• Significant impact on capacity market procurement and LTP

60,000

70,000

80,000

90,000

100,000

110,000

120,000

130,000

140,000

150,000

AIL

(GW

h)

AESO AIL Energy Forecasts (2006 - 2017)

Actual w/ Linear Trend 2017 LTO 2016 LTO2014 LTO 2012 LTO FC 2009FC 2008 FC 2007 FC 2006

2008

2016

2017

38

Year-to-Date Load Recovery• 2017: 3.3% system energy recovery; 4.6% AIL recovery

6,000

6,500

7,000

7,500

8,000

8,500

9,000

9,500

10,000

10,500

11,000

MW

Year-over-Year Load Recovery (7-Day Moving Average)

AIL (2016) AIL (2017) System Energy (2016) System Energy (2017)

Load Growth into 2018

39

• Several large projects ramping up– Fort Hills & Horizon alone exceed AESO reference case for 2019

80,000

81,000

82,000

83,000

84,000

85,000

86,000

87,000

88,000

Dem

and

(MW

/h)

Change in AIL Demand Between 2017 and 2018

Noload growthexceptfornewprojectsrampingup

POOL PRICE DRIVERS

Price

41

Energy price is volatile, lowest since market opened in 2001

$0

$10

$20

$30

$40

$50

$60

$70

$80

$90

$100

Pool

Pric

e ($

/MW

h)

Alberta Electricity Spot Market

2011:SD1/2Gone

2013:Significantsupplyscarcityfromoverlappinglong-termoutages

2014:LoadslowingAdditionalGenerationUnitsbackinservice

2015:LoadshrinksShepardcommissionsImperialunitscommission

2016:LoadshrinksMarginal Cost(PPA)

2017:HigherGHGLoad GrowthMarginalCost

Pool Price

42

$0

$10

$20

$30

$40

$50

$60

$70

$80

$90

Pool

Pric

e ($

/MW

h)

Alberta Electricity Spot Market Forecast

All-Hours Average Pool Price: $66.74/MWh Combined-Cycle Levelized Cost

LoadShrinksMarginal Cost(PPAs)

HigherSGERLoadGrowth

Economic WitholdingOBAGHGPolicyMothball/Retirements

RenewableGrowth

Risingcarbontaxes($40/t, $50/t)

Simple-cycle capturesrenewablevolatility Base-loadCCGT

2020 Pool Price Waterfall Buildup

43

• Higher natural gas prices, load growth, offer behavior, retirements/mothballing, Carbon taxes

• Supply growth (primarily renewable) constrain prices

$0

$5

$10

$15

$20

$25

$30

$35

$40

$45

$50

$55

$60

Pool

Pric

e ($

/MW

h)

Growth in Pool Price Between 2017 and 2020

TRANSMISSION EFFECTS

More Distributed Generation

EDC Associates Ltd. 45

Generation

Transmission

Distribution

Customer

GeneratorStorage

Load

TFO Billing Point

Option M

200 MW

500 MW

250 MW

50 MW

Option M300 MW

DFOBilling Points

Alberta & Saskatchewan Renewable Energy Finance Summit, February 6, 2018 46

DisclaimerThe information and data provided in this report has been obtained or prepared from sources that arebelieved to be reliable and accurate but not necessarily independently verified. EDC Associates Ltd. makesno representations or warranties as to the accuracy or completeness of such information and data nor theconclusions that have been derived from its use. Further, the data in this report is generally of a forecastnature and is based on what are believed to be sound and reasonable methodologies and assumptions,however cannot be warranted or guaranteed with respect to accuracy. Therefore, any use of the informationby the reader or other recipient shall be at the sole risk and responsibility of such reader or recipient.

The information provided in this report and the facts upon which the information is based as well as theinformation itself may change at any time without notice, subject to market conditions and the assumptionsmade thereto. EDC Associates Ltd. is under no obligation to update the information or to provide morecomplete or accurate information when it becomes available.

EDC Associates Ltd. expressly disclaims and takes no responsibility and shall not be liable for any financialor economic decisions or market positions taken by any person based in any way on information presentedin this report, for any interpretation or misunderstanding of any such information on the part of any personor for any losses, costs or other damages whatsoever and howsoever caused in connection with any use ofsuch information, including all losses, costs or other damages such as consequential or indirect losses, lossof revenue, loss of expected profit or loss of income, whether or not as a result of any negligent act oromission by EDC Associates Ltd.

Copyright © EDC Associates This document was prepared under contract by EDC Associates Ltd. and may not be copied or reproduced,translated to electronic media in any form or manner whatsoever, in whole or in part, nor distributed to anythird party without the prior written consent of EDC Associates Ltd. And then only with clearacknowledgement of EDC Associates Ltd. as the author.

Alberta & Saskatchewan Renewable Energy Finance Summit, February 6, 2018 47