1. Fast Start Pricing – Impact Analysis
April 16, 2015 | NEPOOL markets committee
Fast Start Pricing – Impact Analysis
Price Formation When Fast Start Resources Are Committed and Dispatched
Ben Ewing & Jon Lowell
Market development

2. Goals of the Fast Start Pricing Design
Improve price formation by reflecting the cost of fast-start deployments through transparent market price signals.
Improve performance incentives for all resources during tight system conditions when reliability risk is heightened.
Address External Market Monitor’s recommendations
Address shortcomings of the current Fast Start Pricing methodology
Shortcoming #1 - Fast Start assets are generally unable to set price after the first dispatch interval, even though committed and dispatched economically
Shortcoming #2 - Relaxing EcoMin values in the dispatch solution distorts the system energy balance

3. Additional Information Available
These documents have been re-posted for the April MC meeting:
Memo: “Fast-Start Pricing Improvements – Revised Edition”
Detailed explanation of Fast Start Pricing examples
Powerpoint: “Fast Start Pricing” presentation at the March MC meeting
Includes examples from the memo and discussion of Fast Start Pricing design principles

4. Impact analysis overview

5. Study methodology - Summary
11 month study period (Jan 1, 2014 – Dec 2, 2014)
Re-run dispatch and pricing software using FS pricing logic
Simulate intervals when one or more eligible FS units were committed.
~15,000 RT dispatch cases meet this criteria, of ~58,000 total cases in the study period (25% of all cases).
5-min. simulated prices aggregated into hourly LMPs and RMCPs
Use simulated prices to compare actual market outcomes with simulated market outcomes under proposed FS pricing logic
RT energy and reserves, Lost Opportunity Cost, NCPC.

6. Study methodology – Context and Caveats
This is a retrospective simulation study methodology.
It estimates what would have happened in the 2014 study period with the proposed new rules.
Analysis employs the actual load, energy offers, unit commitment, and other system conditions that occurred during the study period.
These are assumed unaffected by the new FS pricing logic.
Future years’ system conditions may differ from the observed conditions during 2014.

7. Real-time Market Impact Summary
Percent
Average RT system energy price increases ($/MWh)
$3.10
4.8%
RT energy charges to load deviations increase1
$20.5 M
7.4%
RT reserve payments increase1,2
$11.6 M
39.8%
New Lost Opportunity Cost payments1,3
$7.5 M -
RT NCPC (net of LOC payment) decreases1,3
-$20.5 M
-8.9%
Notes:
Annualized values
Includes adjustment for Forward Reserve Obligation Charge, eliminating real-time
payment to resources already compensated in the Forward Reserve Market.
3. Excludes approximately 17% of cases for which LOC could not be estimated,
and therefore may underestimate LOC (intervals where Fast Start EcoMins are relaxed under the current methodology)

8. Fast start pricing example – August 19, 2014
A FS unit is dispatched between its Ecomin and Ecomax. It sets price for three 5-min intervals, under both current and proposed pricing logic.
B to C
Current pricing (blue line): FS unit receives DDP at Ecomin. Other units set the price.
Fast start pricing (red line): FS unit sets price (marginal with Ecomin relaxed to zero). D
Prices converge at end of FS unit’s minimum run time.

9. Hourly LMP is unchanged in 70% of hours
No change in 70% of hours
Impact ranges from 1 cent / MWh to $5 / MWh in 20% of hours

10. FS pricing lowers RT NCPC payments, on net
Impact
New Lost Opportunity Cost payments1,2
$7.5 M
RT NCPC decrease1,3
-$20.5 M
Total decrease
-$13 M
NCPC Breakdown
Impact
Non FS Generators1,3
-$10.1 M
FS Generators1,3
-$10.4 M
NCPC impacts are estimated by applying rules in effect as of Hourly Offers implementation to the historical study period.
Notes:
Annualized values
Excludes approximately 17% of cases for which LOC could not be estimated,
and therefore may underestimate LOC.
3. Includes $3.6M of LOC payments as revenue offsetting a portion of total NCPC.

11. Longer term impacts on DAM and FCM
Over time, an increase in RT LMPs will affect DAM and FCM prices.
DAM. An increase in average annual RT LMPs should be expected to increase average annual DA LMPs by a similar amount.
4.8% of the 2014 annual DA market value is approximately $400M.
FCM. An increase in suppliers’ DA market energy revenue should reduce FCM prices, by increasing suppliers’ infra-marginal energy revenue
This lowers FCA net going-forward costs and net CONE
This effect holds, to different magnitudes, whether new or existing sets FCA price
We cannot say with certainty how much one effect will offset the other, as different resources tend to set price in the FCM and DAM.
FS pricing will move money from the FCM into the energy markets, where it strengthens the RT performance incentives for all suppliers (when FS units operate)

12. Impact analysis – additional detail

13. Real-Time Energy Market Impact
Average RT Hub LMP ($/MWh)
Average RT Energy Component ($/MWh)
Charge to RT Load Deviations ($ millions)
Actual
$65.05
$64.49
$256.0
Simulation
$68.23
$67.58
$274.9
Delta
$3.18
$3.10
$18.9
Annualized:
$20.5
Averages are across all hours in the study period

14. RT energy market Impact – monthly breakdown
Largest price impacts seen in Jan – Mar due to tight operating conditions.
For further info on these conditions see the May 2014 PC materials, beginning on slide 128.
*Note: December data includes only two days (12/1/2014 – 12/2/2014)

15. RT energy market Impact – monthly breakdown
Average Increase in RT Hub LMP from FS Pricing ($/MWh)
Increase in Cost to RT Load Deviations from FS Pricing ($M)
Jan
$9.21
$4.59
Feb
$6.38
$2.59
Mar
$6.72
$3.47
Apr
$1.41
$0.50
May
$1.61
$0.67
Jun
$1.76
$1.20
Jul
$0.90
$0.56
Aug
$1.55
$1.03
Sep
$2.70
$3.02
Oct
$0.54
Nov
$0.71
Dec*
$0.51
$0.02
Largest price impacts seen in Jan – Mar due to tight operating conditions
*Note: December data includes only two days (12/1/2014 – 12/2/2014)

16. Average zonal LMP increases from FS Pricing
Minimal price separation across zones, except during tight operating conditions in Jan 2014.
*Note: December data includes only two days (12/1/2014 – 12/2/2014)

17. 63% of hours affected by FS pricing are on-peak
Notes:
*December data includes only two days (12/1/2014 – 12/2/2014)
On-peak hours defined as non-holiday weekdays, hours ending 08-23

18. Real-Time Reserve Market Impacts
Average RMCP 10 spin ($/MWh)
Average RMCP Total 10 ($/MWh)
Average RMCP Total 30 ($/MWh)
Total RT Reserve Payments ($ millions)
Actual
$2.26
$1.39
$1.35
$26.9
Simulation
$3.28
$1.95
$1.91
$37.6
Delta
$1.03
$0.56
$10.7
Annualized:
$11.6
Averages are across all hours in the study period, including those when RMCP = $0.
RMCPs shown are for Rest-of-System.

19. How much more frequently would Hub LMP exceed PER Strike Price?
With RCPFs which were in effect during simulation period: (TMOR = $500, TMNSR = $850)
Number of Hours
Average PER Strike Price* ($/MWh)
Average RT Hub LMP* ($/MWh)
Average Delta ($/MWh)
Actual 2
$499.84
$530.94
$31.10
Simulation 6
$558.36
$600.08
$41.72
With higher RCPFs which are currently in effect (TMOR = $1000, TMNSR = $1500):
Number of Hours
Average PER Strike Price* ($/MWh)
Average RT Hub LMP* ($/MWh)
Average Delta ($/MWh)
Actual 8
$569.50
$761.51
$192.01
Simulation 11
$571.38
$749.56
$178.18
FS pricing increases the estimated number of hours in which Hub LMP > PER Strike Price by 3-4 hours over the study period.
*Notes: Averages are across only those hours in which Hub LMP > PER Strike Price
Slide modified on 4/14/2015 from original posting

20. Next steps

21. Anticipated Schedule February MC meeting – conceptual overview
March MC meeting
Lost Opportunity Cost discussion
Detailed Examples
April MC meeting
Historical simulation of fast start pricing design impacts
Tariff language review
May MC meeting – request MC vote
June PC meeting – request PC vote
FERC filing – summer 2015
Implementation - sometime in 2016