2016 Pool Price Forecast October 2015

2016 Pool Price Forecast
October 2015
The information contained in this document is published in accordance with
the AESO’s legislative obligations and is for information purposes only. As
such, the AESO makes no warranties or representations as to the accuracy,
completeness or fitness for any particular purpose with respect to the
information contained herein, whether express or implied. While the AESO
has made every attempt to ensure the information contained herein is timely
and represents a reasonable forecast, the AESO is not responsible for any
errors or omissions. Consequently, any reliance placed on the information
contained herein is at the reader’s sole risk.
2
Purpose of AESO Price Forecast
• Hourly Price Forecast is Required for the Budget Review
Process
– Forecast feeds cost calculations for Ancillary Services and
Transmission Line Losses
• Fourth year of the AESO providing the Price Forecast
– Price Forecasts from EDC were used prior to the 2013 BRP
3
Forecast Methodology
• Created Using the AURORAxmp Electric Market Model
– Model reflects the Alberta Market Fundamentals
• Random Variables are Used to Generate Price Volatility
– Forced Outages – random times and duration
– Demand – accounts for weather impact
– Gas Prices – lognormal distribution of monthly gas prices
– Wind – random selection of historical wind profiles (new)
– Dynamic Pricing – offer strategies when supply conditions are
tight (new)
– potential long-term forced outages, congestion, unanticipated
load growth, and high/low hydro years are currently not
modeled using random variables
4
Forecast Methodology
• Price Simulation
– Ran 1001 separate price simulations
– Price distributions reflect volatility seen in the Alberta Market
– New model enhancements improved volatility and allowed for
the use of the P50 iteration
• Previously used P95
5
Load Forecast
11,000
Average Alberta Internal Load (MW)
10,500
10,000
9,500
9,000
8,500
8,000
Jan
* 2014 LTO Load Forecast
Feb
2014 Actual
Mar
Apr
May
2015 Actual
Jun
Jul
Aug
2015 Rest of Year*
Sep
Oct
Nov
2016 BRP*
Dec
6
Supply Additions
2,000
Actual
1,500
MW
1,000
500
0
-500
2009
Coal
Hydro
2010
2011
2012
Simple Cycle
Wind
2013
2014
Combined Cycle
Other
2015
Cogeneration
Retirements
2016
7
2016 Simulation Results
Results from 1001 Price Simulations
On-Peak
Off-Peak
Flat
Mean
$53.40
$17.42
$41.41
Min
$39.45
$14.25
$31.62
Pool Price ($/MWh)
P5
P25
Median
$45.20 $49.44 $51.99
$15.69 $16.67 $18.99
$35.75 $38.63 $40.99
P75
$56.53
$18.14
$43.66
P95
$63.59
$19.24
$48.73
Max
$77.73
$22.13
$57.68
Results from the P50 simulation and benchmark
Period
On-Peak
Off-Peak
Flat
AESO
$51.99
$18.99
$40.99
Forward Market
(as of Aug. 31, 2015)
$49.91
$22.20
$40.67
8
Actual/Forecast
$120
25
$100
$89.95
$80.79
$80.19
$76.22
20
$80
$70.36
$62.99
15
$66.95
$54.59
$47.81
$43.93
10
$8.27
$6.30
5
$6.19
$50.88
$49.42
$6.17
$40.99
$40
$39.48
$7.73
$6.10
$3.76
$3.84
$3.79
$4.24
$3.44
$2.27
0
$60
$64.32
$3.01
$2.62
$3.29
11.58
10.08
8.79
8.23
13.99
11.45
12.16
13.15
13.63
22.39
28.10
27.49
11.53
15.27
12.47
2002
2003
2004
2005
2006
2007
2008
2009
2010
2011
2012
2013
2014
2015
YTD
2016
fcst
As of Aug 31, 2015
Pool Price ($/MWh)
Heat Rate (GJ/MWh), Gas Price ($/GJ)
30
Market Heat Rate
Gas Price
$20
$0
Pool Price
9
2015 Price Duration Curve (ytd)
$400
$40
$39.48 as of Aug. 31
$35
$29.65 excluding highest
10 days
Daily Price ($/MWh)
$300
$30
$250
$25
$200
$20
$150
$15
$100
$10
$50
$5
$0
Annual Average Price ($/MWh)
$350
$0
0
25
50
75
100
125
150
175
200
225
Day of Year
Daily Price ($/MWh)
Annual Average Price ($/MWh)
10
2016 Forecasted Cost of Ancillary Services
and Transmission Losses
October 2015
1. Cost of Operating Reserves
Annual Comparison
2014
Forecast
2014
Actual
2015
Forecast
2015
Projected
2016
Forecast
$193.7
$185.3
$130.5
$152.1
$149.1
2014
Forecast
2014
Actual
2015
Forecast
2015
Projected
2016
Forecast
Pool Price ($/MWh)
$48.48
$49.42
$41.49
$39.32
$40.99
Gas Price ($/GJ)
$3.28
$4.24
$4.07
$2.70
$3.29
$ million
Operating Reserves Cost *
* Non-compliance and liquidated damages not included
12
Forecast Methodology
Operating Reserves
• Annual cost of OR is estimated by the sum of forecasted
hourly OR volumes (governed by Alberta reliability
standards) multiplied by the forecasted hourly price of OR
𝑐𝑜𝑠𝑡 =
𝑣𝑜𝑙𝑢𝑚𝑒 ∗ 𝑝𝑟𝑖𝑐𝑒
ℎ𝑜𝑢𝑟,
𝑝𝑟𝑜𝑑𝑢𝑐𝑡,
𝑐𝑜𝑚𝑚𝑜𝑑𝑖𝑡𝑦
• Forecasted cost of OR is evaluated once for each of the
1001 pool price simulations from the AURORAxmp model
$ million
2014
Forecast
2015
Forecast
2016
Forecast
Estimated
$194
$131
$149
Maximum
$366
$262
$253
13
2. Cost of Non-OR Ancillary Services
Annual Comparison
2014
Forecast
2014
Actual
2015
Forecast
2015
Projected
2016
Forecast
Poplar Hills
$2.5
$2.8
$2.5
$2.7
$2.5
Conscripted Services (TMR and OR)
$0.0
$5.4
$0.0
$6.0
$0.0
Reliability Services
n/a
n/a
n/a
$2.1
$2.9
Transmission Constraint Rebalancing
(TCR)
n/a
n/a
n/a
$0.5
$4.0
Black Start Services
$2.8
$1.0
$5.0
$2.1
$2.1
Load Shed Service for Imports (LSSi)
$25.4
$24.4
$25.0
$19.0
$20.0
$ million
Note – there was no contracted Transmission Must-run (TMR) in these years
2014
Forecast
2014
Actual
2015
Forecast
2015
Projected
2016
Forecast
Pool Price ($/MWh)
$48.48
$49.42
$41.49
$39.32
$40.99
Gas Price ($/GJ)
$3.28
$4.24
$4.07
$2.70
$3.29
14
3. Transmission Line Loss Costs
Annual Comparison
2012
Actual
2013
Actual
2014
Actual
2015
Projected
2016
Forecast
Cost ($ million)
$151
$181
$115
$90
$112
Volume (GWh)
2,259
2,325
2,445
2,472
2,577
2012
Actual
2013
Actual
2014
Actual
2015
Projected
2016
Forecast
$64.32
$80.19
$49.42
$39.32
$40.99
Pool Price
($/MWh)
15
Forecast Methodology
Line Losses
• Annual cost of transmission line losses is estimated by the
sum of forecasted hourly volumes multiplied by the
forecasted pool price
𝑐𝑜𝑠𝑡 =
𝑣𝑜𝑙𝑢𝑚𝑒 ∗ 𝑝𝑟𝑖𝑐𝑒
ℎ𝑜𝑢𝑟
• Forecasted cost of line losses is evaluated once for each of
the 1001 pool price simulations from the AURORAxmp model
$ million
2014
Forecast
2015
Forecast
2016
Forecast
Estimated
$117
$105
$112
Maximum
$139
$121
$157
16
4. Wire Costs
Annual Comparison
$ million
2014
Forecast
2014
Actual
2015
Forecast
2015
Projected
2016
Forecast
AUC Approved Wires *
$1,401.5
$1,381.4
$1,367.7
$1,518.0
$1,679.3
Invitation to Bid on Credit
(IBOC)
$1.5
$1.5
$1.5
$1.4
$1.5
Location Based Credit
Standing Offer (LBC SO)
$4.3
$4.1
$4.5
$3.8
$4.0
* Not approved by AESO Board in the annual BRP
17
Thank you
Own Costs
2016 Draft Budget Overview
• 2016 G&A budget
100
98.3
$ Million
98
96.0
96
94.0
94.0
2015
2016
94
92
90
2013
2014
• 2016 energy market trading charge (preliminary)
¢ per MWh
40
30
25.9
32.3
30.3
25.7
2015
2016
20
10
0
2013
2014
2
General & Administrative Costs
YTD August 2015
Forecast
Year End
Variance
YTD Aug
Actual
YTD Aug
Budget
YTD Aug
Variance
42.8
41.0
1.8
61.4
Contract Services and
Consultants
3.4
6.5
(3.1)
9.8
Administration
2.7
3.3
(0.6)
4.9
Facilities
5.1
5.3
(0.1)
7.9
Computer Services and
Maintenance
6.3
5.8
0.5
8.6
Telecommunications
0.9
0.9
(0.0)
1.4
61.2
62.7
(1.4)
94.0
$ Million
Staff Costs
Total Costs
2015
Budget
Differences are due to rounding
3
2016 Budget Overview
• Continued delivery for AESO and industry required initiatives
– Refer to business initiative presentation
– Most 2016 initiatives began in 2015 or prior years
– Ongoing focus on several foundational initiatives:
• Critical Infrastructure Protection in various areas within the AESO
[facilities, processes, capital, etc.]
• Cyber security enhancements
• EMS and market system review and enhancement
• Reflects efficiencies and corporate focus/priorities
• Limited flexibility to incorporate unanticipated initiatives
– Consistent with prior budgets, significant changes will require
additional review and approval
4
General & Administrative Costs
2016 Preliminary Budget
2015
Budget
2016
Budget
61.4
64.8
Contract Services and Consultants
9.8
5.9
Administration
4.9
4.7
Facilities
7.9
7.8
Computer Services and Maintenance
8.6
9.4
Telecommunications
1.4
1.4
94.0
94.0
$ Million
2015
Forecast
Staff Costs
Total Costs
94.0
Differences are due to rounding
5
2016 Preliminary Budget
$ Million
2015 Approved Budget
Staff Costs
94.0
3.4
Contract Services
(3.9)
Administration
(0.2)
Facilities
(0.1)
Computer Services
2016 Preliminary Budget
0.8
(0.0)
94.0
6
2016 Preliminary Budget
$ Million
3.4
Staff Costs
Vacancy rate change (from 8% to 6%)
1.3
New staff for CIP program (7 FTE )
0.9
New staff for succession program (8 FTE )
0.8
Consultant to staff conversions (4 FTE )
0.6
Pay grade averaging, miscellaneous
(0.2)
Contract Services
(3.9)
Competitive Process related
(2.2)
Consultant to staff conversions
(0.8)
Miscellaneous changes
(0.8)
CIP - Critical Infrastructure Protection
7
Notable Changes in 2016
• Vacancy rate reduction due to current trends
• Staff additions related to specific initiatives
• Currently anticipate stable compensation structure
– Will continue to be assessed
• Progression of Competitive Process
– Integration of Fort McMurray West within AESO
– Assessing the timing for next CP project
• Net new maintenance and support costs associated with
annual capital investments
– Impacted by higher US/CDN foreign exchange rate
8
2016 Budget Changes by Department
1.5
1.0
$ Million
0.5
0.0
Market
Services
Transmission
Project Deliv &
Comm
IT
Regulatory
Corporate
Services
Operations
(0.5)
(1.0)
(1.5)
(2.0)
9
Historical G&A Costs
100.0
98.3
96.2
96.1
96.0
94.0
95.0
94.0
94.0
$ Million
90.0
85.0
80.0
75.0
2013 *
2014 *
Actual/Current Forecast
2015
2016
Budget
* Excludes Market System Replacement and Re-engineering project
10
Interest and Amortization
$ Million
Interest
Amortization
YTD Aug
Actual
YTD Aug
Budget
YTD Aug
Variance
2015
Budget
2016
Budget
0.5
0.2
0.3
0.5
0.5
18.0
18.0
(0.0)
26.9
24.4
11
Other Industry Costs
YTD Aug
Actual
YTD Aug
Budget
YTD Aug
Variance
2015
Budget
2016
Budget
AUC Fees – Transmission
8.2
9.3
(1.1)
14.0
12.0
AUC Fees – Energy Market
4.4
4.8
(0.4)
7.2
7.0
Regulatory Process Costs
1.2
1.3
(0.2)
2.0
1.7
WECC/NWPP* Costs
1.2
0.8
0.4
1.2
2.1
15.1
16.3
(1.2)
24.4
22.8
$ Million
Total Costs
* Western Electricity Coordinating Council / Northwest Power Pool
12
Preliminary Energy Market Trading Charge
Prelim
2016
Budget
2015
Budget
2014
Budget
26.4¢
27.0¢
29.2¢
Energy Market (Surplus) / Deficit
(0.8)
3.3
3.1
AESO Component
25.7
30.3
32.3
5.3
5.5
5.6
31.0¢
35.8¢
37.9¢
Trading Charge Components
(¢ per MWh)
AESO Costs
(¢ per MWh)
AUC’s Portion of Energy Market
Administration Fee
Total
Preliminary 2016 trading charge assessment
~ this information will be updated/revised based on the budget amounts that are included in the
Draft 2016 Business Plan and Budget Proposal distributed to stakeholders and the AESO Board
at the end of October
~ this information does not include the Market Surveillance Administrator (MSA) charge which is
communicated to the AESO in the latter part of 2015
13
Activity-based Cost Reporting
• A transparent presentation of the AESO’s operating costs
• Operations of the AESO described using five key processes
– Key processes are unchanged from previous years
• Activity reporting allows for more detailed understanding of
the resources required for process delivery
• No significant shift in priorities/ focus since first presented
14
Summary of AESO G&A Costs
Staff and Contract
Services ($71 million)
2016 Resource Costs ($83 million)
1. Electric System Operations
($42 million)
2. Electric System
Development
($14 million)
3. Customer Access
Services ($10 million)
5. Corporate Services
($11 million)
Computer Services and
Telecomm ($11 million)
Administration ($5 million)
Facilities ($8 million)
Budget of $94 million
4. Market Development
($6 million)
• Proportion of 2016 costs associated with the five
key processes is similar to prior years with no
material shift
15
2016 Draft Capital Budget
Capital Budget - Historical
Capital Expenditures ($ million)
Key Capital Initiatives
2016
2015
2015
2014
2013
Budget Projected Budget Actual Actual
5.3
8.9
7.1
4.7
8.4
Other Capital Initiatives
5.3
3.9
3.3
5.8
7.4
Life Cycle Funding
6.6
3.0
5.6
6.7
6.2
17.1
15.8
16.0
17.2
22.0
Special - MSR
2.5
4.9
4.9
-
-
Special - EMS
17.2
8.2
-
-
-
Special - SCC
1.3
-
-
-
-
38.0
29.0
20.9
17.2
22.0
Sub total
Total
Definitions:
Key Capital Initiatives – Most critical projects that the AESO believes must be completed within the timeframe
identified
Other Capital Initiatives – Other projects that have more flexibility in planning or delivery so timing is not as critical
Life Cycle Funding – Hardware replacements (end of useful life) and recurring software upgrades and leasehold
improvements
2
Capital Budget – Key Messages for 2015
• Total Capital Spend
– 2015 projected is $29.0M
• Factors Include
– General Capital: Reduced “Lifecycle” project spend to
accommodate Energy Management System (EMS) - Phase II
(Definition) project expanded design scope
– Special Capital for EMS: Increase of $8.2M; Approval and
initiation of EMS* Phase III Implementation project
* Identified as a potential special project in 2015 BRP
3
Capital Budget - 2015 draft
Capital Expenditures ($ million)
2016
2015
2015
2014
Budget Projected1 Budget Actual
2013
Actual
Key Capital Initiatives
2
1. Reliability (EMS elements)
3
Reliability (primarily HVDC elements)
2. Critical Infrastructure Protection
3. Cyber Security
4. Wind Integration
4
5. FEOC Regulation Implementation
6. Market Evolution
7. Demand Response
8. Intertie Framework
9. Operating Reserve
10. Cost Accountability
5
11. BUCC Replacement
12. Technology Review (website refresh)
Total Key Capital Initiatives
Other Capital Initiatives
Life Cycle Funding
SubTotal Capital
6
Special - MSR 7
Special - EMS
Special - SCC 8
Total Capital
0.7
0.7
2.5
0.5
0.3
0.0
0.6
5.3
5.3
6.5
17.1
2.5
17.1
1.3
6.0
0.3
0.2
0.7
1.8
0.3
0.2
9.5
3.3
3
15.8
4.9
8.2
-
3.6
0.3
0.4
1.2
1.2
0.4
0.0
7.1
3.3
5.6
16.0
4.9
-
1.0
1.4
0.8
0.3
0.3
0.4
0.4
0.1
4.7
5.8
6.7
17.2
-
0.5
1.5
0.0
0.2
0.6
0.1
2.3
0.2
8.4
7.4
6.2
22.0
-
38.0
29.0
20.9
17.2
22.0
1
August 31, 2015. Spent plus estimate to complete for current year.
5
2
Energy Management System
6
3
High Voltage Direct Current
Fair Efficient Open Competition
7
Market System Replacement & Reegineering
8
System Coordination Centre Expansion
4
Back-up Control Centre
ISO Tariff/Info Mgt Reclassified - Other
4
Capital Budget - Key Messages for 2016
• Initial assessment is that a $38.0M capital budget is required
– Increase of $17.1M from 2015 budget and increase of $9.0M
from 2015 projected
• Factors include
– General Capital
• Critical Infrastructure Protection and Cyber Security
requirements (facilities and information technology)
– Special Capital for Foundational System Upgrades $21.0M
• Market System Replacement and Reengineering project
(business applications and supporting infrastructure – $2.5M)
• Energy Management System Implementation project
(advanced applications and supporting infrastructure - $17.2M)
• System Coordination Centre Expansion Definition - $1.3M
5
Capital Budget – Trend
Total Capital
Budget $38.0M
25.0
22.0
21.0
20.0
17.1
17.1
$ millions
15.8
15.0
13.2
10.0
5.0
0.0
2013 Actual
2014 Actual
Key
Other
2015 Projected
Lifecycle
Total
2016 BRP
Special
6
Capital Budget – “Other Capital Initiatives”
for 2016 - Summary
• Other application or infrastructure upgrades
– Oracle Environment Refresh
– System Enhancements program
– Other:
• Deferral Reporting System
• Financial System Upgrade
• Compliance Reporting Enhancements
7
Capital Budget – “Life Cycle Initiatives” for
2016 – Summary
• Ongoing investment in general infrastructure
– Communications
– Database
– End User Computing
– Enterprise Services
– Monitoring
– Network
– Non-project Capital
– Servers
– Storage
8
Special Projects
Market System Replacement and
Reengineering (MSR)
Program Update
9
MSR Project – Background
On December 9, 2014, the AESO Board approved Phase III of the
Market System Replacement and Reengineering (MSR) project to
address the long-term lifecycle needs of our market systems
Phase I –
Validation/RFI
(2013)
Phase III –
Implementation
(2015 - 2020
tentative)
Phase II –
Sourcing/RFP
(2014)
Phase III
In Progress
Iteration 1
Future Iterations
Design
Short-term
Sustainment
Long-term
Build
2015
2016
Timing TBD
Note: Future iterations are likely to overlap
and run in parallel at certain times
10
MSR Project – Background (Cont.)
Implementation Strategy
– An end-to-end system replacement would require a solution
with broad flexibility to mitigate uncertainty of future market
scenarios
– Phase I research suggested that available solutions do not
have this flexibility and Phase II activities confirmed this
understanding
– As a result, our Phase III implementation strategy is to
incrementally and iteratively address highest priorities with
minimum change until future market scenarios become more
certain
11
MSR Project – 2015 Accomplishments
Iteration 1
Design
Short-term
Sustainment
Long-term
Build
2015
2016
Timing TBD
• Progressed the design of a long-term market systems
foundation enabling sustained and improved reliability
• Progressed the requirements for market systems capabilities
that would address the most likely market evolution scenarios
in the long-term
• As a result of external uncertainties, additional focus was
placed on the planning and design of short-term measures to
sustain the reliability of the our current market systems
12
MSR Project – 2016 Business Plan
Iteration 1
Design
Short-term
Sustainment
Long-term
Build
2015
2016
Timing TBD
• Given external uncertainties, implementation of longer-term
solutions is currently not planned to occur in 2016
• Timing of long-term solution implementation will be reevaluated in 2016 and when we gain more certainty
• In 2016, we plan to implement the short-term measures
designed in 2015 to sustain the reliability of our current
market systems
• Preliminary estimate for 2016 is $2.5M capital
13
Special Projects
Energy Management System (EMS)
Phase III Program
Update
14
EMS III Program - Background
On September 17, 2015, the AESO Board approved Phase III of the
Energy Management System (EMS) Implementation project to
address the long-term lifecycle needs of our energy management
system
Validation
Definition
Implementation
Technical
Assessment
Requirements
Application
Detailed design
Infrastructure
Evaluation of
environment
Cost
Testing
Schedule
Training
Planning and
Management
Deployment
Opportunity
identification
Decision to move
to Definition
Phase
Sustainment
Evergreen Lifecycle management
to optimize
operational costs
Decommission
15
EMS III Program – Implementation Phase
Scope
- Application upgrade Alstom EMS 2.5 to 3.0
- Infrastructure replacement: servers, storage, network,
security and monitoring
- Testing: 10 months duration + 1000 hours of parallel testing
- Training: End users and operational support team
- EMS 2.5 decommissioning
- Life-cycle Management Plan
Target Start: Q4 2015
Target Complete: Q2 2017
Estimated budget: $31.7M (multi-year)
(Excludes capitalized borrowing costs)
16
Special Projects
System Coordination Centre (SCC)
Expansion Program
Update
17
SCC Expansion Program - Background
• In 2006, the Alberta Electric System Operator built a new
System Coordination Center (SCC) to coordinate the Alberta
Interconnected Electric System (AIES).
• Due to the increasing number of AESO employees required
to support AESO Operations, the headcount had grown to
exceed the current capacity of the SCC.
• In 2011, the AESO investigated expanding the existing
building. At that time, the decision was made not to proceed.
• A number of interim solutions have been implemented
however the lack of space and related potential issues
remain a growing problem.
18
SCC Expansion Program - Approach
The program is structured in three distinct phases: Validation
Phase, Definition Phase and the Implementation Phase.
Validation
Q1-Q2 2015
Definition
Q3 2015 – Q3 2016
Implementation
Q3 2016 – Q4 2017
• Validation Phase – Complete
• Definition Phase - Business Case; Requirements
confirmation; Improved timing and cost estimates for the
Implementation Phase
• Current cost estimate for the Definition Phase is in the $1.3M
range
19