MISO 2013-2014 Winter Assessment Report
Information Delivery and Market Analysis
June 2014
Table of Contents
I. Executive Summary.................................................................................................. 3
II. Resource Assessment Analysis ............................................................................... 5
III. Market Demand ........................................................................................................ 6
1. Total Real-Time Energy......................................................................................... 7
2. Load Duration Curve Analysis ............................................................................... 8
IV. Market Supply........................................................................................................... 9
1. Generation Resource Analysis .............................................................................. 9
2. Generation Outages ............................................................................................ 15
V. Market Evaluation and Impacts .............................................................................. 19
1. Price Analysis ...................................................................................................... 19
2. Price Convergence and Comparative Price Analysis12 ........................................ 21
3. Border Price Analysis: MISO vs. PJM prices ....................................................... 25
4. Real-Time Interface Prices at the MISO and PJM Interface ................................ 26
5. Ancillary Services Market Analysis ...................................................................... 27
6. Virtual Transactions ............................................................................................. 30
7. RSG..................................................................................................................... 31
8. FTR ..................................................................................................................... 32
VI. Noteworthy Highlights ............................................................................................. 33
1. Membership: South Region Integration ............................................................... 33
2. Extreme Winter Weather Conditions ..................... Error! Bookmark not defined.
3. Control Center Facilities ...................................................................................... 33
4. South Region ICT Services ................................................................................. 33
5. Value Proposition ................................................................................................ 34
2
I.
Executive Summary
Market outcomes from previous time periods have not been adjusted for
membership changes, unless otherwise noted. Caution should be used when
making any comparisons.
The report provides an assessment of the MISO markets during the 2014 winter
period (December 2013, January 2014, and February 2014). A summary of the 2014
winter season found that MISO markets and reliability operations performed well.
On December 19th 2013, MISO successfully integrated the MISO South Region,
including parts of Arkansas, Louisiana, Mississippi, and Texas. The South Region
integration provides the MISO’s Midwest region easier access to natural gas and
nuclear generation in the south region, balancing the generation fuel mix and better
positioning MISO for future operation challenges.
The winter 2014 season was characterized by historic cold weather throughout
much of the MISO footprint. Extreme cold conditions impacted the MISO Region on
several occasions, with the coldest temperatures in twenty years experienced in early
January. While the conditions presented challenging circumstances, MISO and its
members were able to reliably manage the power grid during this period.
The extreme cold weather resulted in a new winter peak of 109.3 GW on January
6th. The new peak was over 9% higher than the prior winter peak for MISO’s current
membership. Even though load obligation dropped by 3.8GW on January 7th, MISO
experienced tighter supply conditions due to decreased wind generation, less available
generation and reduced imports. MISO curtailed non‐firm exports to non‐deficient
entities after declaring a Maximum Generation Emergency Alert and Warning on the
morning of January 7th.
Overall, temperatures in the MISO footprint during the 2014 winter season were well
below normal. Average hourly Real-Time load exceeded 100GW for 56 hours and the
hourly average load for winter 2014 was 8.1% higher than that of winter 2013 with
membership adjustment.
The MISO region continued to rely on coal-fired generating resources for the
majority of the time. However, impacted by the MISO South integration, coal’s share of
total energy generation declined to 63.2% this winter from 72.6% recorded last winter.
The new MISO South region has relatively less coal-fired generation resources and
more natural gas resources.
The average registered wind capacity for this winter was 13.2 GW, an increase of 6.2%
from last winter. The average hourly wind output was 5,083 MW in the 2014 winter season.
3
•
In general, wind resources performed as expected during the cold weather
conditions. Wind output at MISO’s peak load hours did vary significantly, but those
changes were forecasted in advance, allowing MISO to prepare accordingly.
•
During the extreme cold period in early January, wind generation at the time of
peak fell from approximately 6,600 MW on January 6th to 2,300 MW on January
7th. Although icing and cut-outs impacted wind units, MISO effectively managed the
losses in the same manner as outages on other units were managed.
•
Wind generation in January 2014 was 4,467 GWh and set a new monthly record.
MISO’s market functions performed as expected during the cold weather
conditions. The harsh winter weather put significant upward pressure on market
outcomes.
•
Real-Time average energy and ancillary service market prices for winter
2014 increased substantially when compared with winter 2013, driven by
high load conditions and elevated gas prices.
•
The 3-month average Real-Time LMP for the winter 2014 was $46.88/MWh,
which increased 67.6% when compared with winter 2013.
•
The Real-Time reserve prices in winter 2014 were much higher when
compared with winter 2013. High load conditions and Operating Reserve
scarcity were the primary drivers for the price increase.
•
Twenty 5-minute intervals of operating reserve scarcity occurred on January
7th, 2014, and another twelve occurred on February 11th, 2014.
o On January 7th, fifteen consecutive Operating Reserve scarcity
intervals were experienced during morning ramp period due to the
high load conditions and the forced generation outages.
o On February 11th, Operating Reserve scarcity was driven by high
demand coupled with forced generation outages, including gas
supply issues experienced by some natural gas-fired power plants.
•
The absolute average energy price difference between Day-ahead and
Real-Time was $16.84/MWh in the winter 2014, impacted by volatile RealTime energy price. It was $5.50/MWh in the winter 2013.
•
The combined total of Day-Ahead and Real-Time RSG in winter 2014 was
at the highest level in the recent four winter seasons.
o Total RSG payment in February 2014 was the highest among winter
months since the Ancillary Services Market was launched. 60% of
Real-Time RSG in February 2014 was associated with constraint
mitigation, a significant portion of which was for congestion
management around the Michigan area. Day-Ahead RSG associated
with VLR commitments in February 2014 was 63.6% of the total DayAhead RSG. Over 90.0% of the Day-Ahead RSG associated with
VLR was for the South Region.
4
II.
Resource Assessment Analysis
Table 1: Demand and Capacity Analysis for Monthly Peak Demand hours: Winter 2014.
2013
2014
Dec 30 , HE 19
Jan 6 , HE 19
Feb 7th, HE 19
Instantaneous Peak Load
92,082
109,336
103,070
Reserve Requirement
2,410
1,670
2,410
Peak Load Obligation
94,492
111,006
105,480
Capacity
Real-Time Emergency Offer*
(-) Outages
(-) Offer reduction& Wind Derates
(+) Net Imports
(+) Non-LMR BTMG
(-) Online Stranded
(-) Emergency Ranges
Real-Time Accessible Capacity
Capacity Margin (%)**
142,136
19,342
18,458
2,804
636
2,656
1,931
103,188
9.2%
154,990
23,031
14,609
2,695
1,857
3,754
2,381
115,767
4.3%
155,239
29,280
12,172
3,051
1,571
5,283
1,549
111,577
5.8%
Load
th
2014
th
*Emergency offer minus long leadtime resources
**Capacity Margin = (Real-Time Accessible Capacity minus Peak Load Obligation)/Peak Load Obligation
Table 1 shows the operational analysis of demand and capacity during the
monthly peak demand hours of the three months comprising winter 2014. Per MISO
procedure, Demand Response resources would not be used unless an Energy
Emergency situation was declared. Since no energy emergency occurred in those peak
hours, Demand Response Resources were not included in the Capacity margin
calculation. MISO did not experience any major reliability issues during the winter of
2014.
MISO had 115,767 MW of available capacity to manage this winter’s instantaneous
peak demand of 109,336 MW. Based on available capacity, the capacity margin at the winter
peak load hour on January 6th was 4.3%. Maximum Emergency Generation Alerts/Warning
were issued the operating day January 7th after MISO’s winter peak, due to decreased wind
generation, less available generation and reduced imports.
The peak load hour in December saw the lowest wind generation for this winter,
as shown in Table 2b, Section 4. As a result, generation reductions for Intermittent
Resources were highest in that month, relative to the other monthly peak load hours this
winter.
5
III.
Market Demand
Figure 1, Figure 2 and Figure 3, in this section, show the total cleared Real-Time
energy for December through February for the years 2011 through 2014, the average
hourly load by region for the 2013 and the 2014 winter seasons, and the Load Duration
Curves for the 2014 and the two previous winter seasons respectively.
Relative to the previous winter seasons, load in the MISO market increased
substantially in the 2014 winter season. The increase was driven primarily by
membership changes and by extreme winter weather conditions.
Membership Change: MISO successfully transitioned part of the electric grid of
a four-state region across the south (now called MISO South region) into MISO’s
existing market footprint on December 19th, 2013. The integration added several
transmission owning members into the MISO market footprint. Demand in the South
region made up approximately 20.0%1 of the winter 2014 total Real-Time market
energy; accounting for the major portion of the significant increase in Real-Time energy
(Figure 1) between the 2014 winter season and the previous winter seasons.
Severe Weather Conditions: Overall, temperatures in the MISO footprint during
the 2014 winter season were well below normal. During the period of January 5th to
January 8th, a polar vortex moved through the MISO footprint. Temperatures in many
areas were the coldest experienced in 20 years. Periods of extremely low temperatures
were also experienced between January 26th and January 28th, on February 11th, and
between March 3th and March 4th.
Driven by the extreme low temperatures, a new all-time winter peak load of
109.3GW was set on January 6th, surpassing the previous all-time winter peak for
MISO’s current membership by over 9%. Average hourly Real-Time load exceeded
100GW in 56 hours (Figure 2) and daily instantaneous peak load exceeded 100GW on
13 days in January and February 2014.
For the current MISO membership, the hourly average load for winter 2014 was
approximately 8.1% higher than winter 2013.
1
South region’s Real-Time market demand from December 19th, 2013 to February 28th, 2014 as a percentage of MISO’s Real-Time
market demand from December 1st, 2013 to February 28th, 2014.
6
1.
Total Real-Time Energy
Figure 1: Total Real-Time Energy for the Winter Months of 2011, 2012, 2013 and 2014.
2011
180
2012
2013
2014
160
140
TWh
120
100
80
60
40
20
0
Dec
Jan
Feb
Winter-12
Winter-13
Winter-14
Load has not been adjusted for membership changes.
Figure 2: Average Real-Time Hourly Load by Region for Winter 2013 and Winter 2014.
MW
CENTRAL
NORTH
SOUTH
50
45
40
35
30
25
20
15
10
5
0
Dec
Jan
Winter 2013
Feb
Dec
Jan
Feb
Winter 2014
South region average load for December 2013 includes data from December 1st, 2013 to December 31st, 2013.
7
2.
Load Duration Curve Analysis
The seasonal load duration curve indicates the number of hours during the winter
season when Real-Time Load was greater than a given level within the MISO footprint.
GW
Figure 3: MISO Load Duration Curves** for Winter 2012, Winter 2013, and Winter 2014.
115
110
Hours w ith
Load >100GW
Hours w ith
Load >80GW
Hours w ith
Load >70GW
Hours w ith
Load >60GW
Hours w ith
Load >55GW
105
Winter 2014
56(2.6%)
1020(47.2%)
1619(75.0%)
2017(93.4%)
2097(97.1%)
100
Winter 2013
0(0.0%)
0(0.0%)
39(1.8%)
976(45.2%)
1515(70.1%)
95
Winter 2012
0(0.0%)
0(0.0%)
46(2.1%)
995(45.6%)
1519(69.6%)
90
85
80
75
70
65
60
55
50
45
40
35
30
1
219
437
655
873
1091
1309
1527
1745
1963
2181
Number of Hours
Load has not been adjusted for membership changes.
MISO South Region was integrated into the MISO market footprint on December 19th, 2013.
December 2011 (part of winter 2012) load includes Duke Energy Ohio load, which was successfully transitioned into PJM on January 1st, 2012.
8
Market Supply
1.
Generation Resource Analysis
Winter-12
Winter-13
Winter-14
63.2%
70%
72.6%
80%
68.2%
Figure 4: Total Generation by Fuel Type2 for the Winters of 2012, 2013, and 2014.
60%
50%
2.6%
1.1%
1.5%
13.9%
13.2%
14.4%
7.0%
8.5%
10%
7.5%
8.4%
20%
4.6%
30%
13.3%
40%
0%
Coal
Gas
Wind
Nuclear
Other
Note: Other is comprised of Hydro, Oil, Other, Pet Coke, and Waste.
Figure 5: Total Generation by Fuel Type by Region for Winter 2014.
Central Region
5.3%
24.4%
1.4%
10%
0.5%
7.9%
20%
11.1%
30%
3.8%
40%
23.4%
29.1%
50%
11.1%
41.2%
60%
0.0%
70%
2.5%
80%
South Region
60.3%
90%
North Region
78.1%
IV.
0%
Coal
Gas
Wind
Nuclear
Other
The MISO region continued to rely on coal-fired generating resources the
majority of the time. However, impacted by the generation diversity in the South Region
2
Based on 5-minute unit level generation dispatch target
9
– relatively less coal-fired generation resources and more natural gas resources – coal’s
share of total energy generation declined to 63.2% this winter. In the winter of 2012,
due to historically low gas prices and increased wind generation, coal units accounted
for 68.2% of the total energy produced, which was lower than the percentages noted in
winter 2013.
Natural Gas resources usually are more expensive than other resources and are
generally dispatched at a low capacity factor. In winter 2012, natural gas units
accounted for 8.4% of total MISO generation due to the historically low gas prices.
However, this winter, gas’s share of total generation was even higher than that of 2012
due to the gas-fired generation’s contribution in the South region.
Nuclear units are among the lowest-cost resources and therefore, normally
operate at higher capacity factors. Their percent of the total generation for winter 2014
remained about the same when compared with the winters of 2012 and 2013.
Figure 5 shows the total regional generation by fuel type for winter 2014.
Benefiting from the generation diversity in the South region, less coal and more gas
generation, MISO reduced the dependence on coal and increased the portion of gas
generation. Lower percentage of coal generation in the South Region had a downward
influence on the total coal contribution in MISO. While higher percentage of gas
generation in the South Region contributed to the increase of gas share of total energy
generation.
The interest in renewable energy gained momentum to combat environmental
concerns about the effects of fossil fuel combustion. On June 1st, 2011, MISO
successfully launched Dispatchable Intermittent Resources (DIRs), allowing registered
intermittent resources to participate in the Real-Time energy market. As of Dec 1st,
2014, the registering Dispatchable Intermittent Resources (DIRs), MISO had a total of
10,535 MW of registered DIR capacity.
Table 2a: Percent of Wind Generation at MISO for Winters 2012, 2013 and 2014.
Wind Energy as
a Percentage of
MISO Energy3
DIR Energy as a
Percent of Total
Wind Energy4
Winter 2012
Dec
Jan
Feb
Winter 2013
Dec
Jan
Feb
Winter 2014
Dec
Jan
Feb
7.1%
8.7%
6.9%
7.4%
9.4%
8.1%
6.1%
6.9%
6.3%
17.2%
17.0%
33.3%
53.7%
53.1%
55.6%
81.5%
79.1%
78.8%
The average share of total generation in the MISO region attributed to wind was
6.5% and DIR increased to around 80.0% of the total wind energy in winter 2014.
Figure 6: Hourly Average of Real-Time Wind Generation4 during Winters 2012, 2013 and 2014.
3
4
Hourly ICCP Data
Source: Historical Hourly Wind Data
10
Average Wind Generation
Registered Wind Capacity
13,500
11,500
MW
9,500
7,500
5,500
3,715
4,568
5,203
3,632
3,895
6,032
4,520
4,131
5,087
3,500
1,500
-500
Dec-11 Jan-12 Feb-12
Capacity
Factor
34.8% 43.1% 34.3%
Dec-12 Jan-13 Feb-13
31.7% 42.4%
36.8%
Dec-12 Jan-13 Feb-13
31.7% 46.3%
39.0%
The capacity factor for wind energy is limited by its inherent properties and is
calculated as the ratio of actual wind generation output to the registered wind capacity.
Figure 6 shows that registered wind capacity and average winter wind generation
have consistently grown in the MISO market for the last three winters. The average
registered capacity for this winter was 13,035MW, an increase of 6.2% from that of last
winter.
Wind generation output for this winter averaged 5,083 MW, an increase of 12.0%
from last winter. Wind generation in January 2014 was 4,467 GWh and set a new
monthly record. The instantaneous wind peak this winter was 9,954MW on February
26th, while the all-time wind peak was 10,021 MW set on November 23rd, 2012. Wind
output exceeded 9,000 MW for 92 hours this winter, and it was 60 hours in the last
winter.
The volatility of the wind generation, measured in terms of the standard
deviation, has also been consistently increasing for the last three winter seasons,
presenting potential challenging operational issues. However, the implementation of
Dispatchable Intermittent Resources (DIRs) has resulted in a decrease in MWh of wind
curtailments, as well as the duration of curtailments.
Table 2b: Wind Generation5 at MISO Monthly Peak Load Hours for Winters 2011, 2012, and 2013.
Winter 2012
Winter 2013
Winter 2014
(MW) Dec
Jan
Feb
Dec
Jan
Feb
Dec
Jan
Feb
Peak Load Hour
762
2,243 1,218 6,954 6,839
Wind 2,696 7,562 1,100 2,326
Generation
Wind
3.3%
1.0%
3.1%
1.3% 6.4%
6.6%
Generation % of 3.6% 10.5% 1.6%
Peak Load
11
The table above shows wind generation at the monthly peak load hour for this
winter and the previous winters. Wind generation output was 6,954 MW or 6.4% at the
hour of the 2014 winter peak load on January 6th, 2014.
110%
94.4%
96.8%
95.8%
Figure 7: Average Percentage of time a fuel is at the margin in Real-Time during the winters of 2012, 2013
and 2014.
69.9%
90%
50%
44.8%
48.2%
50.8%
70%
Coal
Gas^^
Winter 2012
1.2%
2.1%
2.5%
-10%
0.1%
0.0%
0.0%
10%
1.4%
1.2%
1.9%
5.9%
5.8%
30%
Hydro
Nuclear
Oil
Winter 2013
Wind
Winter 2014
Note: Binding transmission constraints can produce instances where more than one unit is marginal in the system. Consequently, more than
one fuel may be on the margin; and, since each marginal unit is included in the analysis, the percentage may sum to more than 100%. In
addition, on June 1st, 2011, MISO successfully launched Dispatchable Intermittent Resources (DIRs), allowing wind to participate in the RealTime energy market. ^^Gas excludes Combined Cycle units
Figure 7 above shows that Coal was the major fuel at the margin, setting RealTime LMPs over 90.0% of the time. This was a substantial increase of gas units setting
the price in winter 2014. Impacted by the high gas fired generation in the South Region,
more gas units were committed due to the high load conditions, gas as a marginal fuel,
increased substantially to 50.8% of the time this winter. Consistent with the increase of
wind generation, Dispatchable Intermittent Resources (DIRs) setting the Real-Time
price increased to 69.9% of the time in winter 2014.
Figure 8: Total Imports and Exports during the Winters of 2012, 2013, and 2014.
12
Winter2012
629
Abs Diff of Hourly Imports
1,366
Stdev of Hourly Imports
6,000
5,000
Winter2013
620
866
Winter2014
896
1,267
GWh
4,000
3,000
2,000
1,000
0
Dec-11 Jan-12 Feb-12
RT Imports
Dec-12 Jan-13 Feb-13
RT Exports
DA Imports
Dec-13 Jan-14 Feb-14
DA Exports
Figure 8 shows that similar to previous winters, MISO continued to be a net importer of
electricity this winter. However the net imported energy decreased this winter when
compared with winter 2012 and winter 2013. During the cold snap in January MISO
effectively managed the all-time winter peak and also supported neighboring entities.
The table inserted into Figure 8 shows the absolute differences between RealTime and Day-Ahead hourly imports, and the volatility of Real-Time imports, measured
by standard deviation for the last three winters.
The absolute difference between Real-Time and Day-Ahead imports is important
to MISO’s Real-Time operations, as large differences require unit commitment and
dispatch changes in the Real-Time market relative to the Day-Ahead market. Compared
with winter 2013, the absolute difference and the imports volatility for winter 2014
increased.
13
Figure 9: Average Monthly Generation Fuels Prices: Coal, Natural Gas Spot Prices and Distillate
Fuel Oil: Winters 2012, 2013, and 2014
$26.00
Gas Nominal price
Powder Basin Coal Nominal price
Illinois Basin Coal Nominal price
Distillate Fuel Oil Nominal price
$25.00
$24.00
$23.00
$22.00
$21.00
$20.00
$19.00
$18.00
$/MMbtu
$17.00
$16.00
$15.00
$14.00
$13.00
$12.00
$11.00
$10.00
$9.00
$8.00
$7.00
$6.00
$5.00
$4.00
$3.00
$2.00
$1.00
$0.00
Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb
2012
2013
2014
Note: Source of fuel prices is publicly available government Sources (EIA and ICE). Natural Gas Prices are for Chicago Hub with Price Index = 2000 and Coal
prices are for Illinois Basin with Heat Content = 11,800 Btu/lb. Powder River Basic Coal Heat Content =: 8,800 Btu/lb; Distillate Fuel Oil Heat Content: 5.825
mmbtu/barrel.
Fuel supply conditions influence regional fuel market spot prices (Figure 9).
Such conditions include the proximity of the fuel sources, international export demands
for fuels, contractual terms, delivery certainty, transportation, pollution abatement costs
and competing end-uses of a fuel.
Winter 2014 average Illinois Basin prices remained about the same when
compared with last winter season. Month-over-month coal prices have essentially
remained flat since early 2012. Powder River Basin coal prices increased 18.7% from
winters 2012.
Gas prices, which averaged $8.38/MMBtu in January 2014 and $12.04/MMBtu in
February 2014, were at the highest level since August 2008. The harsh weather
conditions experienced this winter season continued to put a strain on gas supply
conditions and cause high demand for gas in winter 2014. Natural Gas averaged
$2.92/MMbtu in winter 2012, $3.46/MMbtu in winter 2013 and $8.33/MMbtu in winter
2014. Average natural gas price for winter 2014 more than doubled when compared to
winter 2013. Through February 2013, the April 2012 gas price of $2.05/MMbtu was the
lowest since the start of MISO energy markets. The highest price observed since April
2005 was $12.96/MMbtu observed in December 2005.
14
Distillate fuel oil markets in the United States involve two products: low-sulfur
distillate, which is used as a transportation fuel (diesel) for on-highway vehicles, and
high-sulfur distillate, which is used for space heating (heating oil) in the residential and
commercial sectors and as a fuel for other stationary (nontransportation) applications in
the commercial, industrial, and electricity generation sectors. The market’s present
need for oil is reflected in the current price. Prices in distillate fuel oil markets respond
quickly to changes in supply and demand.
Average monthly prices for Distillate Fuel Oil are somewhat volatile. The
Distillate Fuel Oil price in winter 2014 was $23.34/MMbtu, a decrease of 3.2% from
winter 2013. . Oil was marginal 2.5% of the time in winter 2014 which increased when
compared with that with the past two winters, reflective of the colder overall
temperatures this winter.
2.
Generation Outages
Figure 10 shows the generator outages that occurred in each month for the
winters of 2012, 2013, and 2014. Generator Operators are responsible for submitting
generator outages, including derates to MISO. MISO evaluates the impact on
transmission system reliability and helps coordinate the rescheduling of planned
outages and the development of mitigation procedures, when required, to maintain
transmission system reliability.
Figure 10: Monthly Avg. of Generation Outages by Types during the Winters of 2012, 2013, and 2014.
20,000
Forced
Planned
18,000
16,000
14,000
MW
12,000
10,000
8,000
6,000
4,000
2,000
0
Dec-11 Jan-12 Feb-12
Winter-12
Dec-12 Jan-13 Feb-13
Winter-13
Dec-13 Jan-14 Feb-14
Winter-14
Note: Generation outages are point in time data and were extracted in the respective reporting months. Values may change if
extracted again. Derates are not included. Data includes both MISO market and reliability footprints. Please note that in
Winter 2014 Early January experienced the coldest temperatures in two
decades.
The extreme weather conditions affected supply contributing to
15
operational challenges. The average forced generation outages in winter 2014
increased 16.1% when compared with winter 2013. The forced generation outages
during the cold snap period resulted in very tight supply conditions and contributed to
high energy prices, heavy congestions and high RSG payments.
As the severe weather conditions moved into the footprint at the beginning of
January, freezing components and fuel restrictions caused challenges for many units.
Figure 11: Daily Average Forced and Planned Outages for Early January
th
Total Forced Generation outage prior to January 4 includes the forced outages due to mechanical failure and gas
issues.
The Figure 11 above indicates that the increasing forced generation outages during
the polar vortex period. The forced generation outages were broken down in two groups
– forced outages due to gas issues and forced outages due to mechanical failures.
• During polar vortex period (Jan 6th-Jan 8th), natural gas restrictions were a major
impact factor on the gas-fired units which could not procure natural gas during
the cold weather. While planned outages had minor impacts during this cold
weather event,
• Increased forced generation outages on January 7th diminished the capacity
situations and caused MISO to issue the Maximum Emergency Generation
Alert/Warning on that day.
Figure 12: Daily Forced Outage Comparison Breakdown by Fuel Type
16
The figure 12 above provides a historical comparison of forced outages by fuel type.
This data includes only the area that is now MISO’s North and Central Regions to provide
accurate year‐over‐year comparisons since MISO’s South Region was integrated into
MISO footprint on December 19, 2013.
• The total forced outages from gas-fired and oil-fired units increased significantly
due to fuel procurement issues or mechanical failure during the polar vortex
period.
• The outage from coal units decreased notably as coal units are generally base
loaded and are needed to be online to meet high load obligation during the Jan
6-8, 2014.
Figure 13: Daily Energy and ASM Products Pricing
17
•
•
High Real-Time price on Jan 7th mostly due to operating reserve scarcity in He
8. Hourly integrated price spiked over $1,600/MWh for that hour.
On Jan 7th, operating reserve scarcity intervals were noted from 7:05 to 8:15 in
the morning, resulting hourly SMP spiked over $1,600/MWh at the hour ending 8.
The forced generation outage, steep load growth were the main drivers for
operating reserve scarcity.
Figure 13: Daily LMP by hubs and Natural Gas prices by Hubs
$/MWh
Daily LMPs by Hubs
ILL_RT
IND_RT
MICH_RT
MINN_RT
ARK_RT
LOU_RT
TEX_RT
300
250
200
150
100
50
0
1/6/2014
$/MMBTU
Chicago City
$13.19
•
•
1/7/2014
Henry Hub
$4.30
Chicago City
$7.40
1/8/2014
Henry Hub
$4.50
Chicago City
$5.40
Henry Hub
$4.50
Impacted by congestion between the North/Central Regions of the footprint and
the South Region, the Real-Time LMPs at the South Hubs were much higher
when compared with LMPs at Midwest hubs on January 6th.
On January 7th, due to the gas supply issues in Midwest, the Real-Time LMPs at
Midwest hubs were higher than the prices at the South Region hubs.
18
V.
Market Evaluation and Impacts
1.
Price Analysis5
The market price is a manifestation of the prevailing demand and supply
conditions. The price trend and its volatility are basic measures of market behaviors and
performance for a given period. The following section indicates that the MISO market
outcomes were as expected for a competitive market.
For the 2014 winter season, the majority of the footprint experienced coldest
temperatures in two decades. Severe weather events were declared a couple of times
and a Maximum Generation Warning was called on January 7th. The harsh winter
weather put significant upward pressure on the market outcomes. In contrast, the
average temperatures of winter 2013 were above the normal and winter 2012 was one
of the warmest winters in recorded history.
Table 3: MISO Hourly Avg. of RT LMP and DA LMP for 3-months of Winter 2012, 2013, and 2014.
2012
2013
2014
Day
Real
Day
Real
Day
Real
LMP ($/MWh)
Ahead
Time
Ahead
Time
Ahead
Time
Dec
$29.98
$27.91
$28.59
$28.02
35.66
34.01
Jan
$26.10
$24.93
$28.87
$28.46
51.64
49.16
Feb
$25.57
$25.04
$27.68
$27.42
56.42
57.48
3-Mth Avg.
$27.22
$25.96
$28.38
$27.97
$47.91
$46.88
Day-Ahead and Real-Time average energy market prices for winter 2014
increased substantially when compared with winter 2012 and 2013, driven by high load
conditions and gas prices due to the extremely cold weather. The 3-month average
Day-Ahead LMP for winter 2014 was $47.91/MWh, which was 68.8% and 76.0% higher
than the 3-month average of winter 2013 and 2012, respectively. The 3-month average
Real-Time LMP for the winter 2014 was $46.88/MWh, which increased 67.6% and
80.0% respectively when compared with winter 2013 and winter 2012. Daily average
Real-Time LMPs exceed $50.00/MWh for twenty-eight days in winter 2014.
The system-wide hourly average Real-Time price exceeded $100.00/MWh for
one hundred and eight hours this winter, mainly due to reserve shortages and
congestions. The highest system-wide Real-Time hourly LMP for the winter 2014 was
$1780.7/MWh, incurred on January 7th, 2014, in HE 8. Consecutive Operating reserve
scarcity intervals were noted in that hour. The daily system-wide Real-Time LMP
exceeded $180.0/MWh for that day, mainly reflective of the tight operating conditions.
Max Gen Alerts/Warning were declared on that day.
Figure 13: MISO Hourly Avg. of RT LMP and RT Load for Winters of 2012, 2013, and 2014.
5
MISO system-wide prices are based on the hourly average of the hubs.
19
200
120,000
180
100,000
160
80,000
120
MW
$/MWh
140
100
60,000
80
40,000
60
40
20,000
20
0
12/1
12/4
12/7
12/10
12/13
12/16
12/19
12/22
12/25
12/28
12/31
1/3
1/6
1/9
1/12
1/15
1/18
1/21
1/24
1/27
1/30
2/2
2/5
2/8
2/11
2/14
2/17
2/20
2/23
2/26
2/29
0
Month
RTLMP 12
RTLMP 13
RT LMP 14
RT Load 12 RT Load 13 RT Load 14
Dec
$27.91
$28.02
$34.01
60,235
56,830
84,957
Jan
$24.93
$28.46
$49.16
58,735
60,038
82,475
Feb
$25.04
$27.42
$57.48
57,311
59,437
68,449
3-Mth Avg.
$25.96
$27.97
$46.88
58,760
58,768
78,499
The MISO footprint experienced extremely cold weather and recorded 10 days of
daily peak loads over 100 GW in January. A new all-time winter peak load of 109.3GW
was set on January 6th, surpassing the previous all-time winter peak (membership
adjusted) of 99.6GW in 2010. The maximum instantaneous peak load for winter 2013
was 74,430 MW on January 22nd.. On December 19th 2013, the MISO South Region
was successfully integrated into MISO’s market operations.
20
Price Convergence and Comparative Price Analysis12
2.
Figure 14: DA and RT Hourly LMP Convergence for MISO: Winters of 2012, 2013, and 2014.
Avg. DALMP
82
Avg. RTLMP
Avg. Difference (DA-RT)
24.85
18.79
5.79 5.87 4.79
7.06
Dec - 13
5.76 4.45 3.36
Jan - 13
22
12
27.26
25.98
28.40
27.99
32
28.59
28.02
28.87
28.46
27.68
27.42
42
29.98
27.91
26.10
24.93
25.57
25.04
$/MWh
52
35.66
34.01
62
47.62
46.53
51.64
49.16
56.42
57.48
72
Absolute Avg. Diff.
16.84
4.55 5.50
2
Winter-14
Winter-13
Winter-12
Feb - 14
Jan - 14
Feb - 13
Dec - 12
Feb - 12
Jan - 12
Dec - 11
-8
Figure 16 above shows that the hourly averages of both Day-Ahead and RealTime prices for the past three winters. In general, the market has tended to exhibit slight
Day-Ahead price premiums. While Real-Time price premium is mainly impacted by the
Operating Reserve Scarcity in Real-Time. Drive by the exemlely cold weather, the
hourly averages of both Day-Ahead and Real-Time prices during the 2014 winter were
much higher than winter 2012 and 2013, and were the highest since the Ancillary
Service market was started in 2009 as well.
The absolute average price difference increased to $16.84/MWh in the 2014
winter from $5.50/MWh in the 2013 winter, indicating that the price difference almost
trippled. Real-Time price was more volatile this winter, due to the tight operation
conditions.
The average MISO system-wide price difference between the Day-Ahead and
Real-Time markets increased to $1.09/MWh this winter from $0.41/MWh last winter.
21
Figure 15: Scatter Plot of Average Daily DA and RT LMP Differences: Winter 2012.
40
CIN
IND
ILL
MICH
MINN
DA LMP minus RT LMP ( $/MWh)
95% quantile of MISO price difference
for Dec 2011 - Feb 2012
20
0
-20
5% quantile of MISO price difference
for Dec 2011- Feb 2012
CIN
IND
ILL
MICH
MINN
Mean
$0.35
$0.92
$2.30
$1.04
$1.03
StdDev
$3.93
$3.55
$5.50
$3.73
$4.49
95% Quantile
$5.70
$5.73
$13.09
$6.37
$9.14
5% Quantile
-$4.88
-$6.05
-$4.61
-$5.39
-$6.54
29-Feb-12
24-Feb-12
19-Feb-12
14-Feb-12
09-Feb-12
04-Feb-12
30-Jan-12
25-Jan-12
20-Jan-12
15-Jan-12
10-Jan-12
05-Jan-12
31-Dec-11
26-Dec-11
21-Dec-11
16-Dec-11
11-Dec-11
06-Dec-11
01-Dec-11
-40
Figure 16: Scatter Plot of Average Daily DA and RT LMP Differences: Winter 2013.
80
IND
ILL
MICH
MINN
95% quantile of MISO price difference
for Dec 2012- Feb 2013
40
20
0
-20
-40
$6.29
$4.46
$6.97
$5.05
$10.89
$5.85
$9.88
5% Quantile
-$8.57
-$5.60
-$13.79
-$5.81
01-Mar-13
$4.03
95% Quantile
24-Feb-13
StdDev
19-Feb-13
$0.54
14-Feb-13
MINN
$0.36
09-Feb-13
MICH
$0.63
04-Feb-13
ILL
$0.14
30-Jan-13
20-Jan-13
15-Jan-13
10-Jan-13
05-Jan-13
31-Dec-12
26-Dec-12
21-Dec-12
16-Dec-12
11-Dec-12
-80
06-Dec-12
5% quantile of MISO price difference
for Dec 2012- Feb 2013
IND
Mean
25-Jan-13
-60
01-Dec-12
DA LMP minus RT LMP ( $/MWh)
60
22
Figure 17: Scatter Plot of Average Daily DA and RT LMP Differences: Winter 2014.
170
IND
DA LMP minus RT LMP ( $/MWh)
120
ILL
MICH
MINN
ARK
LOU
95% quantile of MISO price difference
for Dec 2013- Feb 2014
70
20
-30
-80
-130
5% quantile of MISO price difference
for Dec 2013- Feb 2014
IND
ILL
MICH
MINN
ARK
LOU
Mean
$5.10
$4.73
$7.84
$1.56
-$4.63
-$0.50
StdDev
$39.65
$29.29
$40.29
$23.36
$21.80
$22.49
95% Quantile
-$19.20
-$28.12
-$31.53
-$22.82
-$42.74
-$41.99
5% Quantile
$29.87
$25.35
$52.56
$21.95
$15.60
$21.79
01-Mar-14
24-Feb-14
19-Feb-14
14-Feb-14
09-Feb-14
04-Feb-14
30-Jan-14
25-Jan-14
20-Jan-14
15-Jan-14
10-Jan-14
05-Jan-14
31-Dec-13
26-Dec-13
21-Dec-13
16-Dec-13
11-Dec-13
06-Dec-13
01-Dec-13
-180
The scatter diagrams in Figures 15, 16 and 17 above, based on statistical
analysis, show daily average hourly price differences between the Day-Ahead and RealTime markets at the MISO Hubs during the 2012, 2013, and 2014 winters, respectively.
The table inserted within the scatter diagrams contains additional statistics
calculated from DA-RT LMP differences based on data over the three winter months of
each year. The estimated measures of price dispersion reflect price volatility due to
demand-supply interactions that occurred to clear the respective markets. Price
differences between Day-Ahead and Real-Time markets exist due to market
uncertainties inherent in a competitive bidding process, expectations of participants,
transmission constraint management practices, and the way RAC and Real-Time
resource commitment processes are implemented.
Most of the observations clustered around the zero line show a general
convergence pattern. The data points outside the statistical reference bands indicate
relative price divergence between the Day-Ahead and Real-Time markets at the
respective hubs. Congestions and scarcity were the major contributors to price
volatility.
Winter 2014brought coldest temperatures in two decades and extreme conditions
affected supply contributing to operational challenges. Extremely weather resulted in
record levels of energy prices and price volatilities. DA/RT price convergence was poor
during peak and off-peak periods this winter.
23
On January 6th and 7th, Operating Reserve scarcity was experienced which
caused sharp Real-Time price spikes and resulted in significant Real-Time premiums
for all the hubs. On January 7th, in HE 8, the system-wide hourly Real-Time LMP
exceeded $1700.00/MWh due to the consecutive Operating Reserve scarcity intervals
in that hour.
On January 27th and 28th, Day-Ahead prices were over $300/MWh across the
North and Central Regions due to the transmission constraints, which resulted in large
Day-Ahead price premiums for the Indiana and Minnesota Hubs.
The Operating Reserve scarcity on February 11th caused sharp Real-Time price
spikes and resulted in significant Real-Time premiums for all the hubs. Twelve
Operating Reserve scarcity intervals, in total, were noted on that day.
Impacted by congestion between the North/Central Regions of the footprint and
the South Region, the Real-Time LMPs at the South Hubs were much higher when
compared with Day-Ahead LMPs for several days in February
The Michigan Hub, in particular, was impacted by heavy congestion around the
Michigan area. The Hub experienced hourly LMPs that exceeded $100.00/MWh for total
242 hours in the Day-Ahead market. Congestion around the Michigan area contributed
to the high Day-Ahead premiums in January and February.
Figure 18: Monthly Hourly Average Price Comparison across MISO and Neighboring Markets:
Winter 2012, 2013, and 2014.
$180
Winter - 12
Winter - 13
$160
Winter - 14
139
$140
138
$/MWh
$120
$100
77
$80
$60
$40
48
27 28
32 34
84
75
31
39
36
73
47
26 28
32 33
78
71
29
39
34
$20
$MISO
PJM
NYISO
ISO-NE
Day - Ahead Market
MISO
PJM
NYISO
ISO-NE
Real-Time Market
Figure 18 shows the hourly average prices in the Day-Ahead and Real-Time
markets for MISO6 and neighboring RTO markets during the winters of 2012, 2013, and
2014. Relative to the previous two winters, winter 2014 average LMPs across all the
6
MISO system-wide prices are based on the hourly average of the hubs.
24
ISOs increased in both the Day-Ahead and Real-Time markets, consistent with the
increased weather sensitive load and gas supply stress this winter.
When compared with the neighboring RTO markets, the average energy prices in
MISO were relatively low. MISO experienced winter peak conditions on January 6th.
Reduced peak load obligations on subsequent days freed up resources allowing MISO
to assist PJM as the extreme cold temperatures moved into the East. General grid
resiliency and flexibility allowed MISO to assist neighbors during these events.
3.
Border Price Analysis: MISO vs. PJM prices
In order to evaluate price convergence between the two adjacent RTO markets,
MISO performed a comparative evaluation of prices at the individual MISO and PJM
border buses. The buses chosen for the analysis are electrically close (or identical) and
representatively spread across the PJM/MISO border. The LMPs used in the analysis
are hourly integrated values.
Table 4: Average price at the MISO and PJM border buses during the 2012 winter.
Buses
P
Dec-11
MISO
PJM
Jan-12
MISO
P
P
Feb-12
MISO
PJM
P
$5.27
$22.08
$24.72
$6.97
$21.72
$25.23
$5.08
$25.63
$27.64
$6.88
$27.16
$29.36
PJM
Kincaid (PJM)
Vs Coffen (MISO)
$8.24 $21.53 $24.51
$7.29 $21.57 $26.41
Cook (PJM)
vs Palisades ( MISO) $6.81 $28.61 $31.31
$8.63 $27.13 $29.02
P is the absolute price difference between PJM and MISO.
Winter - 12
MISO
PJM
Table 5: Average price at the MISO and PJM border buses during the 2013 winter.
Buses
Kincaid (PJM)
Vs Coffen (MISO)
Cook (PJM)
vs Palisades ( MISO)
P
Dec-12
MISO
PJM
P
Jan-13
MISO
PJM
P
Feb-13
MISO
PJM
P
Winter - 13
MISO
PJM
$7.80
$22.00
$21.78
$8.37
$25.18
$27.01
$7.65
$23.78
$26.04
$7.95
$23.65
$24.91
$6.69
$27.53
$27.87
$8.26
$27.56
$30.87
$8.82
$28.89
$32.47
$7.89
$27.96
$30.33
P is the absolute price difference between PJM and MISO.
Table 6: Average price at the MISO and PJM border buses during the 2014 winter.
Buses
Kincaid (PJM)
Vs Coffen (MISO)
Cook (PJM)
vs Palisades ( MISO)
P
Dec-13
MISO
PJM
P
Jan-14
MISO
PJM
P
Feb-14
MISO
PJM
P
Winter - 14
MISO
PJM
$7.26
$27.55
$30.07
$34.43
$37.69
$58.75
$23.19
$43.95
$47.93
$21.58
$36.14
$45.50
$6.68
$30.86
$32.09
$36.38
$52.47
$69.01
$58.05
$91.00
$51.00
$32.90
$57.01
$50.69
P is the absolute price difference between PJM and MISO.
Tables 4, 5 and 6 above show price comparisons at the PJM and MISO border
buses between the 2012, 2013, and 2014 winter seasons. The absolute price
differences in winter 2014 were much wider than winters of 2012 and 2013 at all the
border buses.
25
4.
Real-Time Interface Prices at the MISO and PJM Interface
MISO continuously imports energy from, and exports to, external regions. This
section analyzes the Real-Time interchange transactions between MISO and PJM.
These transactions may fulfill long-term or short-term bilateral contracts, or take
advantage of short-term price differentials. MISO’s imports from PJM and MISO’s
exports to PJM are scheduled in the MISO market at a single interface node -- MISO’s
PJM Interface. Similarly, PJM’s imports from MISO and its exports to MISO are
scheduled in PJM’s market at a single interface node -- PJM’s MISO Interface. MISO
estimated (i) LMPs at both the MISO and PJM Interfaces; (ii) the Economic Inefficiency;
and (iii) the Revenue7 for the winters of 2012, 2013 and 2014.
Table 7 below shows summary statistics for the Real-Time hourly LMPs at
MISO’s PJM Interface and PJM’s MISO Interface. During the winter 2014, the hourly
average of MISO LMP at its MISO Interface was $46.85/MWh, while the PJM LMP at its
PJM Interface was $47.14/MWh; a difference of -$0.27/MWh. While in the winter of
2013, the hourly average of the MISO LMP was higher than the hourly average of PJM
LMP by a difference of $0.78/MWh.
Table 7: Real-Time Hourly Interface Prices for the Winters of 2012, 2013 and 2014.
Interface LMP
Average
Winter
2012
MISO LMP at its PJM
Interface
PJM LMP at its MISO
Interface
Interface Price Difference
(MISO – PJM )
Absolute Interface Price
Difference (MISO – PJM )
Winter
2013
$ 26.76
$27.80
$ 25.65
$27.02
$ 1.12
$0.78
$6.15
$6.40
Standard Deviation
Winter
2014
$46.85
$47.14
-$0.27
$21.52
Winter
2012
Winter
2013
$ 10.93
$12.27
$ 9.04
$11.05
$11.88
$15.21
$10.23
$13.81
Winter
2014
$59.38
$90.26
$77.78
$74.74
During winter 2014, the standard deviation of the PJM Real-Time hourly price at
its MISO Interface was $90.26/MWh, while the standard deviation of MISO LMP at its
PJM Interface was $59.38/MWh. This indicates that the volatility of the MISO LMP at its
PJM Interface was less than the volatility of the PJM LMP at its MISO Interface.
7 Revenue is interface price difference (MISO’s PJM Interface price minus PJM’s MISO Interface price) multiplied by the net MWh flow from PJM to
MISO
26
Table 8: Economic Inefficiency and Revenue for Winters 2012, 2013 and 2014.
Winter
2012
% of hours when flow is not consistent with the interface price
51%
differences (MISO – PJM )
Economic Inefficiency (in millions)
$9.69
Overall Revenue from Real-Time Scheduling (in millions)
$5.51
Winter
2013
Winter
2014
47%
50%
$3.66
$4.06
$27.05
$19.70
An economic inefficiency occurs when the direction of energy flows is not
consistent with price differentials. The economic inefficiency for a particular hour was
defined as economic losses when aggregate flow was from the RTO with a high
interface price to the RTO with a low interface price. This was estimated as the negative
of the minimum of zero and the interface price difference multiplied by the MWh of flow.
The direction of energy flows was consistent with price differentials in 50% of hours for
winter 2014. The estimated value of Economic Inefficiency for the winter 2014 was $27
million, as shown in the above table.
As indicated in Table 8 above, despite economically inefficient transactions for a
part of the winter period, it must be noted that MPs may collectively make money by
engaging in Real-Time scheduling at the PJM and MISO interfaces. In winter 2014, out
of 2,160 hours, market participants earned revenues of $46.74 million in 1,070 hours
and incurred losses of $27.05 million in 1,090 hours, yielding overall revenues of $19.70
million. This was a significant increase from the overall Real-Time scheduling revenues
earned in winter 2013 of $4.06 million, mainly attributed to the increased overall
interface price divergence and rising interchange quantities between PJM and MISO.
5.
Ancillary Services Market Analysis
On December 17th, 2012, MISO began Frequency Regulation Compensation
(FERC Order 755) in order to compensate frequency regulating resources on the actual
regulation service provided. On December 19th, 2013, the MISO South Region was
successfully integrated into MISO’s market operations.
27
Figure 19: MISO Wide Daily Day-Ahead and Real-Time MCPs: Winters 2012, 2013, and 2014.
REG_RT_MCP
REG_DA_MCP
RT_REGMILEAGE
SPIN_DA_MCP
SUPP_RT_MCP
SUPP_DA_MCP
$100
Winter-2012
$90
Winter-2013
SPIN_RT_MCP
Winter-2014
$80
$/MWh
$70
$60
$50
$40
$30
$20
$10
12/1/2011
12/7/2011
12/13/2011
12/19/2011
12/25/2011
12/31/2011
1/6/2012
1/12/2012
1/18/2012
1/24/2012
1/30/2012
2/5/2012
2/11/2012
2/17/2012
2/23/2012
2/29/2012
12/6/2012
12/12/2012
12/18/2012
12/24/2012
12/30/2012
1/5/2013
1/11/2013
1/17/2013
1/23/2013
1/29/2013
2/4/2013
2/10/2013
2/16/2013
2/22/2013
2/28/2013
12/6/2013
12/12/2013
12/18/2013
12/24/2013
12/30/2013
1/5/2014
1/11/2014
1/17/2014
1/23/2014
1/29/2014
2/4/2014
2/10/2014
2/16/2014
2/22/2014
2/28/2014
$0
Figure 19 above shows the daily average price trends of the Ancillary Service
Product (AS) clearing prices during the previous three winters.
The marginal clearing prices in winter 2014 were much higher when compared
with winter 2012 and winter 2013. High load conditions and Operating Reserve scarcity
were the primary drivers for the price increase. In addition, gas supply related
generation outage issues put significant upward pressure to the ancillary service
market.
On January 7th, fifteen consecutive Operating Reserve scarcity intervals were
experienced during morning ramp period due to the high load conditions and the forced
generation outages. The daily average of Ancillary Service product prices exceeded
$100.00/MWh. On February 11th, twelve Operating Reserve scarcity intervals occurred,
causing a very high daily average of Ancillary Service product prices.
Table 9 below shows the percent change in ancillary service prices from winter
2014 against winters 2012 and 2013.
Table 9: MISO Wide Ancillary Service Price Comparison - Winter 2014 to Winters 2012 and 2013.
MCP ($/MWh)
Winter 2012
Winter 2013
DA Regulation
9.3%
63.8%
DA Spinning
24.4%
107.2%
DA Supplemental
110.0%
133.5%
RT Regulation
RT Regulation Mileage
($/MW)
RT Spinning
RT Supplemental
18.4%
NA
57.4%
240.0%
103.8%
144.9%
259.1%
556.3%
28
Tables 10a-c below summarize hourly statistics of price dispersion
characteristics for MISO-wide ancillary service product market clearing prices (MCPs)
during the winters of 2012, 2013, and 2014.
The maximum hourly Real-Time Ancillary Service prices over the last three
winters were observed on January 7th, 2014, in HE 8. Consecutive Operating Reserve
scarcity intervals were experience during that hour due to the high load conditions and
the forced generation outages. The price for each product approached $1100.00/MWh
at that time. Hourly Real-Time LMP exceeded $1700.00/MWh for that hour and fiveminute LMP exceeded $2000.0/MWh for some intervals.
Table 10a: MISO Wide Hourly MCP Summary Statistics for the Winter 2012.
Winter 2012
MCP ($/MWh)
Maximum Average
DA Regulation
$28.71
$7.50
DA Spinning
$12.57
$1.51
DA Supplemental
$8.29
$0.89
RT Regulation
RT Regulation Mileage
($/MW)
RT Spinning
RT Supplemental
Minimum
$2.23
$0.55
$0.50
Standard
Deviation
$3.25
$1.45
$0.62
Coeffient
of
Variation*
43.3%
96.3%
69.4%
$142.51
$7.48
$1.95
$6.83
91.4%
$121.59
$94.19
$1.22
$0.56
$0.17
$0.17
$3.87
$2.16
316.4%
382.6%
Minimum
$1.27
$0.32
$0.32
Standard
Deviation
$4.24
$1.35
$0.28
Coeffient
of
Variation*
60.2%
95.8%
44.6%
Table 10b: MISO Wide Hourly MCP Summary Statistics for the Winter 2013.
Winter 2013
MCP ($/MWh)
Maximum Average
DA Regulation
$47.32
$7.05
DA Spinning
$15.35
$1.41
DA Supplemental
$5.00
$0.64
RT Regulation
RT Regulation Mileage
($/MW)
RT Spinning
RT Supplemental
$316.00
$7.65
$1.22
$10.77
140.7%
$3.21
$0.32
$0.00
$0.31
97.1%
$269.61
$232.72
$1.53
$0.48
$0.18
$0.18
$7.11
$5.15
463.5%
1075.1%
Standard
Deviation
$8.41
Coeffient
of
Variation*
68.5%
Table 10c: MISO Wide Hourly MCP Summary statistics for the Winter 2014.
Winter 2014
MCP ($/MWh)
Maximum Average
DA Regulation $106.78
$12.28
Minimum
$2.05
29
DA Spinning
DA Supplemental
RT Regulation
RT Regulation Mileage
($/MW)
RT Spinning
RT Supplemental
$70.53
$70.53
$3.12
$2.07
$0.45
$0.45
$4.72
$4.60
151.1%
221.8%
$1,359.50
$15.24
$1.38
$39.05
256.3%
$5.82
$0.66
$0.06
$0.47
70.9%
$1,187.08
$1,100.00
$4.39
$3.70
$0.13
$0.13
$33.90
$32.03
771.6%
865.5%
* The Coefficient of Variation is used as a statistical measure of price volatility.
6.
Virtual Transactions
Virtual transactions are purely financial positions that can be taken in the DayAhead energy market and do not have to be backed by physical generation or load. As
per the FERC order approving a revised methodology, Real-Time RSG allocation
changed on April 1st, 2011, allocating costs for congestion management to fluctuations
impacting a congested area, as well as to market wide deviations. The result of the new
RSG allocation methodology was anticipated to lead to reduced virtual trading costs and
therefore, increase virtual trading.
The chart below shows MISO’s virtual supply and demand volumes in the winters
of 2012, 2013, and 2014.
Figure 20: Monthly Avg. of Cleared Virtual Load and Cleared Virtual Supply during the Winters of
2012, 2013, and 2014.
6000
Virtual Load
Virtual Supply
Net
5000
4000
3000
MW
2000
1000
0
-1000
-2000
-3000
Winter 2014
Winter 2013
Winter 2012
Feb-14
Jan-14
Dec-13
Feb-13
Jan-13
Dec-12
Feb-12
Jan-12
Dec-11
-4000
Net is defined as the difference between Cleared Virtual Load and Cleared Virtual Supply.
In the winter of 2014, the volumes of cleared virtual demand increased by 18.0%,
while cleared virtual supply decreased 0.2%, relative to the respective volumes in winter
2013. Net virtual load, as the difference between cleared virtual load and cleared virtual
supply, increased significantly this winter.
30
7.
RSG
Millions
Figure 21: MISO Market Wide RSG Make Whole Payments in Day-Ahead and Real-Time Markets Winters of 2012, 2013 and 2014.
45.00
Real-Time RSG MWP
Day-Ahead RSG MWP
40.00
35.00
30.00
$28.31
25.00
20.00
15.00
$5.92
$12.23
10.00
5.00
$2.63
0.00
Dec
$11.44
$3.28
$4.37
$1.68
$1.21
$2.62
$2.38
$1.69
$1.92
$4.93
Jan
Feb
Dec
Jan
Feb
Dec
Winter 2012
Winter 2013
Jan
$14.86
Feb
Winter 2014
*Based on data extracted early May 2014. Values may change due to resettlement.
Figure 21 above shows the Day-Ahead and Real-Time RSG uplifted to the
market. Both Day-Ahead and Real-Time RSG Make Whole Payments increased
substantially in the 2014 winter season.
Real-Time RSG Make Whole Payments were impacted by high natural gas
prices (see Figure 9 in Section 4), high loading conditions that were driven by the
severe winter weather, and heavy congestion. Day-Ahead RSG Make Whole Payments
were also impacted by high natural gas prices and by VLR commitments in the South
Region.
The total of February’s Day-Ahead and Real-Time RSG is the highest for any
winter month since the Ancillary Services Market was launched in 2009. Over 60.0% of
February’s Real-Time RSG was associated with constraint mitigation, a significant
portion of which was for congestion management around the Michigan area. The local
congestion was driven by high weather-sensitive loads, and generation and
transmission outages. Day-Ahead RSG associated with VLR commitments in February
was 63.6% of the total Day-Ahead RSG. Over 90.0% of the Day-Ahead RSG associated
with VLR was for the South Region.
31
8.
FTR
Table 11: MISO FTR Funding and Shortfall
Winter 2012
Millions
Dec
Jan
Feb
Total
* Based
FTR
Target
Credit
Alloc.
$99
$64
$50
$212
Winter 2013
FTR
Funding
FTR
Target
Credit
Alloc.
FTR
Target
Credit
Alloc.
FTR
Funding
$99
$64
$50
$212
100%
100%
100%
100%
$118
$111
$102
$331
$106
$105
$91
$303
Winter 2014
Funding
Percent
FTR
Target
Credit
Alloc.
FTR
Funding
Funding
Percent
90%
95%
89%
91%
$159
$444
$460
$1,062
$157
$444
$446
$1,047
99%
100%
97%
99%
on data extracted early April 2013. Values may change due to resettlement.
Table11 above shows that the monthly FTR funding levels improved during the
winter of 2014. February 2014 had the lowest funding level for the season. February’s
funding was impacted by binding constraints caused by West-East transfers, primarily
wind-driven, and outages that occurred after the FTR model cutoff.
32
VI.
Noteworthy Highlights
1.
Membership: South Region Integration
After more than two years of intensive planning and training, MISO successfully
transitioned a four-state region of the electric grid across the south into MISO’s existing
market footprint on December 19th, 2013.
The integration, which extends MISO’s operational and market footprints from
Manitoba, Canada all the way to the Gulf of Mexico, also adds over 18,000 miles of
transmission, approximately 50,000 megawatts of generation capacity, and
approximately 30,000 MW of peak load into the MISO footprint and makes MISO one of
the largest power grid operators in the world.
Amongst other benefits, MISO’s increased scale will drive benefits through
expanded options for generation commitment and dispatch from a more diverse set of
fuel types. MISO’s increased scale will also drive benefits through improved reliability
and reduce regulation and spinning reserve requirements by consolidating balancing
authorities.
2.
Control Center Facilities
On December 10th, 2013, MISO completed the relocation of its operations from
the St. Paul, MN facility to the new Eagan, MN facility. In conjunction with the move,
MISO modified the designations for the various operating regions. The ‘Carmel’ region
is now referred to as the ‘Central’ region and the ‘St. Paul’ region is now referred to as
the ‘North’ region. The ‘South’ region continued with its designation. No changes to the
physical boundaries of the regions took place.
On March 14th, 2014, MISO broke ground for a new operations center in Little
Rock, Arkansas. This action marks the next phase of the successful integration of the
South region on December 19th, 2013. The new facility will serve as the regional control
center for the South region, housing services that include real-time operations, market
operations, customer relations, government and regulatory affairs, information
technology and administrative support. The operations center is expected to be in
service in the spring of 2015.
3.
South Region ICT Services
The Independent Coordinator of Transmission (ICT) services are now concluded
commensurate with the integration of the Entergy system into the MISO market. MISO
33
successfully transitioned as the provider of ICT services for Entergy on December 1st,
2012 conducting, amongst other duties, the Weekly Procurement Process and the
processing (i.e. study, coordination, and approval) of generation and transmission
outage requests for the Entergy System.
4.
Value Proposition
With growing energy demands throughout MISO's footprint, MISO’s services help
ensure reliable, least-cost delivered energy. MISO’s Value Proposition documents how
MISO unlocks billions in annual benefits for the region.
On February 13th, 2014, MISO released an updated Value Proposition analysis
indicating that MISO’s services provided between $2.1 billion and $3.0 billion in regional
benefits in 2013. The benefits were driven by enhanced reliability, more efficient use of
the region’s existing transmission and generation assets, and a reduced need for new
assets.
MISO’s Value Proposition affirms MISO’s core belief that a collective, regionwide approach to grid planning and management delivers the greatest benefits. MISO’s
landmark analysis serves as a model for other grid operators and transparently
communicates the benefits in everything we do.
34