Impacts of the Transition to a Capacity Market on the Alberta Electricity Market
Allen Crowley, MBAEDC Associates Ltd.
403-648-0632 [email protected]
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
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•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
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$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)
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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
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0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
Capa
city
Fac
tor (
%)
Quarter-over-Quarter Heat Rate Forecast Comparison
Wind Solar
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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
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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
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Alberta & Saskatchewan Renewable Energy Finance Summit, February 6, 2018 47