Nov 15, 2015 - software or data errors that do not accurately reflect the application of the ..... o Under-scheduling lo
State of the Market Report Fall 2015
September – November 2015 SPP Market Monitoring Unit December 21, 2015
TABLE OF CONTENTS
FALL 2015 SUMMARY
1
PRICES
2
CONGESTION
26
GENERATION
32
UNIT COMMITMENT
49
VIRTUAL ENERGY
55
TRANSMISSION CONGESTION RIGHTS
65
UPLIFT
68
Appendix
82
Acronyms, Market Participants, Asset Owners
DISCLAIMER The data and analysis in this report are provided for informational purposes only and shall not be considered or relied upon as market advice or market settlement data. The Southwest Power Pool Market Monitoring Unit (SPP MMU) makes no representation or warranties of any kind, express or implied, with respect to the accuracy or adequacy of the information contained herein. The SPP MMU shall have no liability to recipients of this information or third parties for the consequences arising from errors or discrepancies in this information, or for any claim, loss or damage of any kind or nature whatsoever arising out of or in connection with (i) the deficiency or inadequacy of this information for any purpose, whether or not known or disclosed to the authors, (ii) any error or discrepancy in this information, (iii) the use of this information, or (iv) a loss of business or other consequential loss or damage whether or not resulting from any of the foregoing. Copyright © 2015 by Southwest Power Pool, Inc. Market Monitoring Unit. All rights reserved.
FALL 2015 SUMMARY
• On October 1, 2015, the Integrated System (IS), made up of Western Area Power Administration Upper Great Plains Region, Basin Electric Power Cooperative and Heartland Consumers Power District, joined the SPP Integrated Marketplace. This addition added about 5,000 MW of peak demand and 7,600 MW of generating capacity, which includes tripling SPP’s current hydroelectric capacity. • Gas costs continue to drop with an average Panhandle Hub cost of $2.00/MMBtu for November 2015. Average gas cost for Fall 2015 was $2.25/MMBtu compared to $3.76/MMBtu in Fall 2014. o Average RTBM LMP for Fall 2015 was $20.73/MWh, compared to $29.57/MWh in Fall 2014. 47 o Average DAMKT LMP for Fall 2015 was $19.98/MWh, compared to $28.17/MWh in Fall 2014. 53 • Over the last two years, generation by coal-powered resources has 61declined by over ten percentage points, from 62.7% of total generation in 2013, to 52.1% 64 in 2015. This decline has been covered primarily by increases in generation at nuclear (up 3.4%), wind (up 3.7%) and combined-cycle gas (3.3%) plants. 73 Hydro generation increased by 2.1% over the two year period, primarily attributable to the additional hydro resources gained with the addition of the Integrated System. Generation at gas simple-cycle plants declined 1.9% from Fall 2013 to 2015. SPP Market Monitoring Unit Fall 2015 State of the Market Report
1
1.1 Electricity Prices and Gas Costs
PRICES
• This metric presents gas cost from the Panhandle Eastern Pipeline (PEPL) compared to electricity prices in the SPP footprint. o Although the cost at PEPL is not an exact cost that may be experienced by a particular market participant or resource, the cost serves as a proxy for the overall gas costs experienced across the footprint. • Historically gas prices and Real-Time prices have been highly correlated in SPP. o Workably competitive markets should experience highly correlated gas costs and energy prices in general. o Overall this trend has carried over from the EIS market into the Integrated Marketplace. o Although electricity prices and gas costs are highly correlated over time, some periods, especially summer months, experience divergence. • Average gas costs in Fall 2015 ($2.25/MMBtu) were just over 40% lower than those experienced in Fall 2014 ($3.76/MMBtu).
SPP Market Monitoring Unit Fall 2015 State of the Market Report
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PRICES
$50
$5
$40
$4
$30
$3
$20
$2
$10
$1
$0
$0
Sep 14
Oct 14
Nov 14
Dec 14
Jan 15
Feb 15 Mar 15 Apr 15 May 15 Jun 15
DA LMP
DA LMP RT LMP Gas Cost
Sep 14 $29.32 28.72 3.75
Jul 15
RT LMP
Oct 14 Nov 14 Dec 14 Jan 15 Feb 15 Mar 15 Apr 15 May 15 Jun 15 $30.25 $29.15 $27.83 $25.15 $24.22 $21.96 $21.60 $22.84 $24.76 29.10 26.71 27.65 23.84 24.12 20.46 20.66 21.73 24.20 3.62 3.90 3.34 2.81 2.56 2.50 2.29 2.58 2.54
Aug 15
Sep 15
Oct 15
Nov 15
Gas Cost ($/MMBtu)
LMP ($/MWh)
1.1 Electricity Prices and Gas Costs
Gas Cost
Jul 15 Aug 15 Sep 15 $28.21 $25.58 $22.45 26.30 23.78 21.97 2.68 2.59 2.52
Oct 15 Nov 15 $20.38 $19.35 18.79 19.19 2.22 2.00
Gas Cost is represented by cost at the Panhandle Eastern Pipeline
SPP Market Monitoring Unit Fall 2015 State of the Market Report
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1.2 Day-Ahead and Real-Time Prices
PRICES
• The following figure shows the Locational Marginal Price (LMP) for the DayAhead Market and the Real-Time Balancing Market. This is calculated by taking the simple average of LMP at the SPP North and SPP South hubs. o The LMP is made up of Marginal Energy Component (MEC) Marginal Congestion Component (MCC) Marginal Loss Component (MLC) • Overall, Day-Ahead and Real-Time prices continue to decrease as gas costs decrease.
SPP Market Monitoring Unit Fall 2015 State of the Market Report
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1.2 Day-Ahead and Real-Time Prices
PRICES
$50 DA LMP
RT LMP
LMP ($/MWh)
$40
$30
$20
$10
$0
Sep 14
Oct 14
Nov 14
Dec 14
Jan 15
Feb 15
Mar 15
Apr 15
May 15
Jun 15
Jul 15
Aug 15
Sep 15
Oct 15
Nov 15
Day Ahead DA MEC DA MCC DA MLC DA LMP
Sep 14 30.15 -0.46 -0.38 29.32
Oct 14 Nov 14 Dec 14 Jan 15 Feb 15 Mar 15 Apr 15 May 15 Jun 15 31.79 32.66 28.49 25.63 24.48 23.41 22.76 22.64 24.42 -1.11 -2.90 -0.38 -0.29 -0.08 -1.13 -0.73 0.56 0.48 -0.43 -0.62 -0.29 -0.19 -0.19 -0.32 -0.44 -0.36 -0.15 30.25 29.15 27.83 25.15 24.22 21.96 21.60 22.84 24.76
Jul 15 Aug 15 Sep 15 28.09 25.77 22.59 0.21 0.01 0.17 -0.09 -0.21 -0.30 28.21 25.58 22.45
Oct 15 Nov 15 20.45 19.84 0.22 -0.43 -0.29 -0.07 20.38 19.35
Real Time RT MEC RT MCC RT MLC RT LMP
Sep 14 30.17 -1.04 -0.42 28.72
Oct 14 Nov 14 Dec 14 Jan 15 Feb 15 Mar 15 Apr 15 May 15 Jun 15 31.93 31.63 28.29 24.65 24.83 22.70 23.16 22.42 23.54 -2.41 -4.37 -0.46 -0.58 -0.50 -1.89 -2.07 -0.30 0.75 -0.42 -0.56 -0.19 -0.23 -0.22 -0.35 -0.44 -0.40 -0.09 29.10 26.71 27.65 23.84 24.12 20.46 20.66 21.73 24.20
Jul 15 Aug 15 Sep 15 25.81 23.40 21.79 0.51 0.60 0.47 -0.02 -0.21 -0.28 26.30 23.78 21.97
Oct 15 Nov 15 18.43 17.80 0.65 1.60 -0.29 -0.21 18.79 19.19
MEC - Marginal Energy Component SPP Market Monitoring Unit Fall 2015 State of the Market Report
MCC - Marginal Congestion Component
MLC - Marginal Loss Component 5
1.3 Price Contour Maps
PRICES
• The following price contour maps provide an overall picture of congestion and price patterns in the footprint. o Blue represents lower prices and red represents higher prices. o Significant color changes across the map signify constraints that limit the transmission of electricity from one area to another. o Some other factors that can influence congestion and resulting prices are generator and transmission outages, weather events, differences in fuel prices and differences in temperatures across the footprint. • Overall, pricing patterns between Day-Ahead and Real-Time are similar. o Lower prices are prevalent in the north due to less expensive generation in the area, and the west-central part of the footprint due to abundant low-cost wind generation in that area. o The southwestern corner of the footprint, northwest Oklahoma, and northern North Dakota typically experiences the highest average prices in SPP. • Maps for the Fall period, as well as the twelve month prices, are shown and each broken down for on-peak and off-peak periods. • For areas added to the SPP market footprint with the addition of the Integrated System, values shown represent only October and November 2015. SPP Market Monitoring Unit Fall 2015 State of the Market Report
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1.3 Price Contour Maps Day-Ahead (September-November 2015) Day-Ahead Off-Peak
SPP Market Monitoring Unit Fall 2015 State of the Market Report
PRICES
Day-Ahead On-Peak
7
1.3 Price Contour Maps Real-Time (September-November 2015) Real-Time Off-Peak
SPP Market Monitoring Unit Fall 2015 State of the Market Report
PRICES
Real-Time On-Peak
8
1.3 Price Contour Maps Day-Ahead (December 2014-November 2015) Day-Ahead Off-Peak
SPP Market Monitoring Unit Fall 2015 State of the Market Report
PRICES
Day-Ahead On-Peak
9
1.3 Price Contour Maps Real-Time (December 2014-November 2015) Real-Time Off-Peak
SPP Market Monitoring Unit Fall 2015 State of the Market Report
PRICES
Real-Time On-Peak
10
1.4 Day-Ahead and Real-Time Price Divergence
PRICES
• The following figure shows the Day-Ahead to Real-Time price divergence at the SPP system level. o Price divergence % is calculated as [(RT Monthly Average LMP / DA Monthly Average LMP) - 1], using system prices for each interval (RTBM) or hour (DAMKT). o The divergence (absolute) is calculated by taking the absolute value of the divergence for each interval (RTBM) or hour (DAMKT). • The SPP Markets are experiencing some divergence between Day-Ahead and Real-Time. o This price divergence can be at least partially explained by the significant price volatility in the Real-Time Market. o Prices are expected to be more volatile in the Real-Time Balancing Market than the Day-Ahead Market.
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1.4 Day-Ahead and Real-Time Price Divergence
PRICES
LMP ($/MWh)
$40 $30 $20 $10 $0
Sep 14
Oct 14
Nov 14
Dec 14
Jan 15
Feb 15
DA LMP
Mar 15
Apr 15
RT LMP
May 15
Jun 15
Jul 15
Aug 15
Sep 15
Oct 15
Nov 15
Divergence (ABS)
80%
Divergence
60% 40% 20% 0%
-20% -40% -60%
Sep 14
Oct 14
Nov 14
Dec 14
Jan 15
Feb 15
Mar 15
Divergence % Sep 14 DA LMP $29.33 RT LMP 28.72 Divergence % -3.8% Divergence (ABS) 7.24 Divergence % (ABS) 29.6%
Apr 15
May 15
Jun 15
Jul 15
Sep 15
Oct 15
Nov 15
Divergence % (ABS)
Divergence % is calculated as (RT LMP / DA LMP) - 1 Oct 14 Nov 14 Dec 14 Jan 15 Feb 15 Mar 15 Apr 15 May 15 Jun 15 $30.22 $29.14 $27.64 $25.16 $23.93 $22.06 $21.39 $22.71 $24.46 29.01 26.71 27.67 23.84 24.11 20.46 20.65 21.74 24.22 -6.5% -11.6% -1.3% -7.5% -1.3% -46.9% -7.4% -7.2% -0.9% 8.98 9.31 6.88 5.40 5.01 6.20 7.31 5.83 5.24 33.5% 41.0% 27.2% 23.5% 21.9% 75.3% 54.9% 31.8% 23.4%
SPP Market Monitoring Unit Fall 2015 State of the Market Report
Aug 15
Jul 15 Aug 15 Sep 15 $28.14 $25.69 $22.41 26.30 23.82 21.97 -5.3% -6.7% -9.9% 5.18 4.46 4.38 17.0% 17.6% 29.2%
Oct 15 Nov 15 $20.42 $19.47 18.79 19.18 -12.3% -4.1% 3.69 5.48 26.1% 35.6% 12
1.5 Average LMP by Load-Serving Entity
PRICES
• Pricing patterns in the Integrated Marketplace have generally stayed consistent across time. o The far southwest portion of the SPP footprint generally experiences the highest average prices. o Entities in Nebraska and the west central portion of the footprint generally experience the lowest average prices. o Since the addition of the Integrated System on October 1, a few areas in North Dakota are experiencing high prices. o These differences are driven by congestion patterns and high levels of low-cost generation. • Both Day-Ahead and Real-Time LMPs are shown on the Fall and twelve month charts.
SPP Market Monitoring Unit Fall 2015 State of the Market Report
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$14 AECC/AECC AEPM_X/AEPM BEPM/BEPM BEPM/NMCA_X CHAN/CHAN EDEP/EDEP FREM/FREM GRDX/GRDX GSEC/GSEC HMMU/HMMU INDN/INDN KBPU/KBPU KCPS/KCPS KCPS/UCU KMEA/EMP1_X KMEA/EMP2_X KMEA/EMP3_X KMEA/EUDO_X KPP/KPP LESM/LESM MEAN/FCU_X MEAN/MEAN MEAN/NCU_X MEAN/NELI_X MECB/MECB MEUC/MEUC MIDW/MIDW MRES/MUMZ_X NSPP/NSPP NWPS/NWMT_X NWPS/NWPS OGE/OGE OMPA/OMPA OPPM/OPPM REMC/CWEP SEPC/SEPC SPSM/SPSM TEA/NPPM TEA/SPRM TNSK/GATE_X TNSK/TNGI_X TNSK/TNHP_X TNSK/TNHU_X UGPM/MMPA_X UGPM/OTP_X UGPM/SMGT_X UGPM/UGPM WFES/WFES WRGS/1073 WRGS/COWP WRGS/KN01 WRGS/PARL WRGS/PBEL WRGS/PLWC WRGS/WRGS
MP/AO
LMP ($/MWh)
1.5 Average LMP by Load-Serving Entity (September-November 2015)
DAMKT LMP
SPP Market Monitoring Unit Fall 2015 State of the Market Report
SPP DAMKT Average RTBM LMP
PRICES
$32
$30
$28
$26
$24
$22
$20 19.78 19.27
$18
$16
SPP RTBM Average
Only load-serving entities are included. Data from Integrated System entities only includes October and November.
14
$14 AECC/AECC AEPM_X/AEPM BEPM/BEPM BEPM/NMCA_X CHAN/CHAN EDEP/EDEP FREM/FREM GRDX/GRDX GSEC/GSEC HMMU/HMMU INDN/INDN KBPU/KBPU KCPS/KCPS KCPS/UCU KMEA/EMP1_X KMEA/EMP2_X KMEA/EMP3_X KMEA/EUDO_X KPP/KPP LESM/LESM MEAN/FCU_X MEAN/MEAN MEAN/NCU_X MEAN/NELI_X MECB/MECB MEUC/MEUC MIDW/MIDW MRES/MUMZ_X NSPP/NSPP NWPS/NWMT_X NWPS/NWPS OGE/OGE OMPA/OMPA OPPM/OPPM REMC/CWEP SEPC/SEPC SPSM/SPSM TEA/NPPM TEA/SPRM TNSK/GATE_X TNSK/TNGI_X TNSK/TNHP_X TNSK/TNHU_X UGPM/MMPA_X UGPM/OTP_X UGPM/SMGT_X UGPM/UGPM WFES/WFES WRGS/1073 WRGS/COWP WRGS/KN01 WRGS/PARL WRGS/PBEL WRGS/PLWC WRGS/WRGS
MP/AO
LMP ($/MWh)
1.5 Average LMP by Load-Serving Entity (December 2014 - November 2015)
DAMKT LMP
SPP Market Monitoring Unit Fall 2015 State of the Market Report
SPP DAMKT Average RTBM LMP
PRICES
$34
$30
$26
$22 23.12 22.37
$18
SPP RTBM Average
Average is for the previous 12 months. Only load-serving entities are included. Data from Integrated System entities only includes October and November.
15
1.6 Price Volatility by Load-Serving Entity
PRICES
• Volatility is represented using the coefficient of variation, which is the standard deviation divided by the mean for the period for each load-serving entity. • Although overall volatility is higher than experienced in the EIS market, the relative patterns remain similar. o The entities in the northern portion of the footprint tend to experience the lowest average prices while they typically see the most volatility in pricing. o Some higher volatility in the Integrated Marketplace can be attributed to scarcity pricing.
SPP Market Monitoring Unit Fall 2015 State of the Market Report
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0.0
DAMKT Volatility
AECC/AECC AEPM_X/AEPM BEPM/BEPM BEPM/NMCA_X CHAN/CHAN EDEP/EDEP FREM/FREM GRDX/GRDX GSEC/GSEC HMMU/HMMU INDN/INDN KBPU/KBPU KCPS/KCPS KCPS/UCU KMEA/EMP1_X KMEA/EMP2_X KMEA/EMP3_X KMEA/EUDO_X KPP/KPP LESM/LESM MEAN/FCU_X MEAN/MEAN MEAN/NCU_X MEAN/NELI_X MECB/MECB MEUC/MEUC MIDW/MIDW MRES/MUMZ_X NSPP/NSPP NWPS/NWMT_X NWPS/NWPS OGE/OGE OMPA/OMPA OPPM/OPPM REMC/CWEP SEPC/SEPC SPSM/SPSM TEA/NPPM TEA/SPRM TNSK/GATE_X TNSK/TNGI_X TNSK/TNHP_X TNSK/TNHU_X UGPM/MMPA_X UGPM/OTP_X UGPM/SMGT_X UGPM/UGPM WFES/WFES WRGS/1073 WRGS/COWP WRGS/KN01 WRGS/PARL WRGS/PBEL WRGS/PLWC WRGS/WRGS
MP/AO
1.6 Price Volatility by Load-Serving Entity (September-November 2015)
SPP Market Monitoring Unit Fall 2015 State of the Market Report
SPP DAMKT Volatility RTBM Volatility
PRICES
1.6
1.4
1.2
1.0
0.8
0.6 0.68
0.4
0.2 0.28
SPP RTBM Volatility
Only load-serving entities are included. Data from Integrated System entities only includes October and November.
17
0.0
DAMKT Volatility
AECC/AECC AEPM_X/AEPM BEPM/BEPM BEPM/NMCA_X CHAN/CHAN EDEP/EDEP FREM/FREM GRDX/GRDX GSEC/GSEC HMMU/HMMU INDN/INDN KBPU/KBPU KCPS/KCPS KCPS/UCU KMEA/EMP1_X KMEA/EMP2_X KMEA/EMP3_X KMEA/EUDO_X KPP/KPP LESM/LESM MEAN/FCU_X MEAN/MEAN MEAN/NCU_X MEAN/NELI_X MECB/MECB MEUC/MEUC MIDW/MIDW MRES/MUMZ_X NSPP/NSPP NWPS/NWMT_X NWPS/NWPS OGE/OGE OMPA/OMPA OPPM/OPPM REMC/CWEP SEPC/SEPC SPSM/SPSM TEA/NPPM TEA/SPRM TNSK/GATE_X TNSK/TNGI_X TNSK/TNHP_X TNSK/TNHU_X UGPM/MMPA_X UGPM/OTP_X UGPM/SMGT_X UGPM/UGPM WFES/WFES WRGS/1073 WRGS/COWP WRGS/KN01 WRGS/PARL WRGS/PBEL WRGS/PLWC WRGS/WRGS
MP/AO
1.6 Price Volatility by Load-Serving Entity (December 2014 - November 2015)
SPP Market Monitoring Unit Fall 2015 State of the Market Report
SPP DAMKT Volatility RTBM Volatility
PRICES
1.4
1.2
1.0
0.8 0.69
0.6
0.4 0.33
0.2
SPP RTBM Volatility
Volatility is for the previous 12 months. Only load-serving entities are included. Data from Integrated System entities only includes October and November.
18
1.7 Trading Hub Prices
PRICES
• The next figure shows monthly average Day-Ahead and Real-Time prices for the two Trading Hubs in SPP: the North and South hubs. o A trading hub is a settlement location consisting of an aggregation of price nodes developed for financial and trading purposes. • Due to an abundance of lower-cost generation in the northern part of the SPP footprint, prices at the North Hub are consistently lower. o The average spread between the North and South Hub for Fall 2014 was $14.03 and was less than half at $6.73 for Fall 2015. • The North Hub has shown a consistent day-ahead premium in price up until November 2015 when Day-Ahead LMP was slightly lower than Real-Time.
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1.7 Trading Hub Prices
PRICES
$50
$40
$/MWh
$30
$20
$10
$0
Sep 14
Oct 14
Nov 14
Dec 14
North DAMKT
SPP Market Monitoring Unit Fall 2015 State of the Market Report
Jan 15
Feb 15
Mar 15
North RTBM
Apr 15
May 15
Jun 15
South DAMKT
Jul 15
Aug 15
Sep 15
Oct 15
Nov 15
South RTBM
20
1.8 Ancillary Service Prices
PRICES
• The following figures show Marginal Clearing Prices (MCP) for ancillary services in the SPP Integrated Marketplace. • Starting September 24, 2014, the zonal limits were removed as these particular limits were no longer needed to ensure deliverability of operating reserves, thus all zones have identical prices beyond September. o Figures shown for all months include the SPP average when different prices were in effect for reserve zones. • On March 1, 2015, SPP implemented its Regulation Compensation market design in compliance with FERC Order 755. It includes payment to market participants based on changes in energy output for regulation deployment. The regulation service market clearing price is comparable to the regulation MCP prior to March 1, 2015. The new regulation mileage MCP is set to the highest mileage offer of any resource cleared for regulation service. Regulation deployment does not depend on the mileage offer, so the mileage MCP does not directly relate to the marginal cost of regulation deployment.
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1.8 Ancillary Service Prices - Regulation $24
PRICES Regulation Up
$/MWh
$18
$12
$6
$0
Sep 14
Oct 14
Nov 14
Dec 14
Jan 15 Feb 15 Reg Up RT
$24
Mar 15 Apr 15 May 15 Reg Up DA
Jun 15 Jul 15 Aug 15 Reg Up Mileage RT
Sep 15
Oct 15
Nov 15
Jun 15 Jul 15 Aug 15 Reg Down Mileage RT
Sep 15
Oct 15
Nov 15
Regulation Down
$/MWh
$18
$12
$6
$0
Sep 14
Oct 14
SPP Market Monitoring Unit Fall 2015 State of the Market Report
Nov 14
Dec 14
Jan 15 Feb 15 Reg Down RT
Mar 15 Apr 15 May 15 Reg Down DA
22
1.8 Ancillary Service Prices - Reserves
PRICES
$8
Spinning Reserves
$/MWh
$6
$4
$2
$0
Sep 14
Oct 14
Nov 14
Dec 14
Jan 15
Feb 15
Mar 15
Apr 15
May 15
Jun 15
Spin RT $10
Jul 15
Aug 15
Sep 15
Oct 15
Nov 15
Aug 15
Sep 15
Oct 15
Nov 15
Spin DA
Supplemental Reserves
$/MWh
$8 $6 $4 $2 $0
Sep 14
Oct 14
Nov 14
Dec 14
Jan 15
Feb 15
Supp RT
SPP Market Monitoring Unit Fall 2015 State of the Market Report
Mar 15
Apr 15
May 15
Jun 15
Jul 15 Supp DA
23
1.9 Price Corrections
PRICES
• On occasion, SPP may have to re-price Real-Time intervals because of software or data errors that do not accurately reflect the application of the Tariff. o Events that may result in data input errors include, but are not limited to: bad or missing SCADA, load forecast error, missing intervals, or human error. Reserves (spin and supplemental) are shown by reserve zones: • This chart shows both the percentage of Real-Time intervals that were repriced during the month and the average total $ change per re-priced interval. • Calculations are as follows: o EIS – Monthly Average Hourly Repriced Amount (Absolute Value) represented as a percentage of the Monthly Average Price 𝑀𝑀𝑀𝑀𝑀𝑀𝑀𝑀ℎ𝑙𝑙𝑙𝑙 𝑆𝑆𝑆𝑆𝑆𝑆(𝐴𝐴𝐴𝐴𝐴𝐴(𝐻𝐻𝐻𝐻𝐻𝐻𝐻𝐻𝐻𝐻𝐻𝐻 𝐼𝐼𝐼𝐼𝐼𝐼𝐼𝐼𝐼𝐼𝐼𝐼𝐼𝐼 𝑃𝑃𝑃𝑃𝑃𝑃𝑃𝑃𝑃𝑃 − 𝐻𝐻𝐻𝐻𝐻𝐻𝐻𝐻𝐻𝐻𝐻𝐻 𝐹𝐹𝐹𝐹𝑛𝑛𝑛𝑛𝑛𝑛 𝑃𝑃𝑃𝑃𝑃𝑃𝑃𝑃𝑃𝑃))⁄𝑀𝑀𝑀𝑀𝑀𝑀𝑀𝑀ℎ𝑙𝑙𝑙𝑙 𝐻𝐻𝐻𝐻𝐻𝐻𝐻𝐻𝐻𝐻 𝑀𝑀𝑀𝑀𝑀𝑀𝑀𝑀ℎ𝑙𝑙𝑙𝑙 𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴 𝑃𝑃𝑃𝑃𝑃𝑃𝑃𝑃𝑃𝑃
o IM – Monthly Average Interval Repriced Amount (Absolute Value) represented as a percentage of the Monthly Average Price 𝑀𝑀𝑀𝑀𝑀𝑀𝑀𝑀ℎ𝑙𝑙𝑙𝑙 𝑆𝑆𝑆𝑆𝑆𝑆(𝐴𝐴𝐴𝐴𝐴𝐴(𝐼𝐼𝐼𝐼𝐼𝐼𝐼𝐼𝐼𝐼𝐼𝐼𝐼𝐼𝐼𝐼 𝐼𝐼𝐼𝐼𝐼𝐼𝐼𝐼𝐼𝐼𝑎𝑎𝑎𝑎 𝑃𝑃𝑃𝑃𝑃𝑃𝑃𝑃𝑃𝑃 − 𝐼𝐼𝐼𝐼𝐼𝐼𝐼𝐼𝐼𝐼𝐼𝐼𝐼𝐼𝐼𝐼 𝐹𝐹𝐹𝐹𝐹𝐹𝐹𝐹𝐹𝐹 𝑃𝑃𝑃𝑃𝑃𝑃𝑃𝑃𝑃𝑃))⁄𝑀𝑀𝑀𝑀𝑀𝑀𝑀𝑀ℎ𝑙𝑙𝑙𝑙 𝐼𝐼𝐼𝐼𝐼𝐼𝐼𝐼𝐼𝐼𝐼𝐼𝐼𝐼𝐼𝐼𝐼𝐼 𝑀𝑀𝑀𝑀𝑀𝑀𝑀𝑀ℎ𝑙𝑙𝑙𝑙 𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴 𝑃𝑃𝑃𝑃𝑃𝑃𝑃𝑃𝑃𝑃
SPP Market Monitoring Unit Fall 2015 State of the Market Report
24
PRICES
10%
$1.00
8%
$0.80
6%
$0.60
4%
$0.40
2%
$0.20
0%
$0.00
Sep 14
Oct 14 Nov 14 Dec 14 Jan 15 Feb 15 Mar 15 Apr 15 May 15 Jun 15 Average $ change per interval
Jul 15
Aug 15 Sep 15
Oct 15 Nov 15
Average $ change per interval
% of intervals with price corrections
1.9 Price Corrections
% intervals price corrected
All price corrections are Real-Time.
SPP Market Monitoring Unit Fall 2015 State of the Market Report
25
2.1 and 2.2 Congestion by Shadow Price
CONGESTION
• The impact of a constraint on the market can be illustrated by its shadow price, which reflects the intensity of congestion on the path represented by the flowgate. o The shadow price indicates the marginal value of an additional MW of relief on a constraint in reducing the total production costs. o The shadow price is also a key determinant in the Marginal Congestion Component of the LMP for each pricing point. • Areas experience congestion, caused by many factors, including transmission and generation outages (planned or unplanned), weather events, and external impacts. • Figure 2.1 shows both Day-Ahead and Real-Time congestion by shadow price for the three month Fall period. • Figure 2.2 shows both Day-Ahead and Real-Time congestion by shadow price for the previous twelve months and includes projects that may provide relief to these congested flowgates.
SPP Market Monitoring Unit Fall 2015 State of the Market Report
26
CONGESTION
$80
80%
$70
70%
$60
60%
$50
50%
$40
40%
$30
30%
$20
20%
$10
10%
$0
0%
DA Average Shadow Price
RT Average Shadow Price
DA % Intervals Congested
% Congested
Shadow Price ($/MWh)
2.1 Congestion by Shadow Price (September-November 2015)
RT % Intervals Congested
% Intervals Congested includes both breached and binding intervals Flowgate Name WDWFPLTATNOW TEMP56_21085 TEMP13_21262 OSGCANBUSDEA TEMP49_21150 TMP168_21247 WODFPLWODXFR NEORIVNEOBLC TMP144_21263 TEMP74_20773
SPP Market Monitoring Unit Fall 2015 State of the Market Report
Owner SPP SPP M2M MISO SPP M2M MISO SPP SPP M2M SPP M2M SPP SPP
Region Western Oklahoma Texas Panhandle North Dakota Texas Panhandle North Dakota Western Kansas Western Oklahoma SW Missouri North Dakota Wichita area
Flowgate Location Woodward-FPL Switch 138kV ftlo Tatonga-Northwest 345kV (OGE) Tuco-Lubbock East 115kV ftlo Tuco-Jones Sub 230kV (SPS) McHenry Xfmr 230kV (GRE) ftlo Lelando-Logan Wa 230kV (WAUE) Osage Switch-Canyon East 115kV ftlo Bushland-Deaf Smith 230kV (SPS) Rugby Xfmr 230/115kV (OTP-WAUE) ftlo Rugby-Balta Jct 230kV (GRE-OTP) Knoll-Redline 115kV (WR) ftlo Gentleman-Red Willow 345kV (NPPD) Woodward-FPL Switch 138kV (OGE) ftlo Woodward Xfmr 138/69kV (OGE) Neosho-Riverton 161kV (WR-EDE) ftlo Neosho-Blackberry 345kV (WR-AECI) Charlie Creek-Roughrider 115kV ftlo Charlie Creek-Watford 230kV (WAUE) Milan Tap-Clearwater 138kV (WR-SECI) ftlo Wichita-Thistle 345kV (SECI-WR)
27
CONGESTION
$60
60%
$40
40%
$20
20%
$0
0%
DA Average Shadow Price
RT Average Shadow Price
DA % Intervals Congested
% Congested
Shadow Price ($/MWh)
2.2 Congestion by Shadow Price (December 2014-November 2015)
RT % Intervals Congested
% Intervals Congested includes both breached and binding intervals Flowgate Name OSGCANBUSDEA WDWFPLTATNOW TUBDOBBENGRI NEORIVNEOBLC WODFPLWODXFR BRKXF2BRKXF1 BULMIDBUFNOR NPLSTLGTLRED SUNAMOTOLYOA ARCKAMARCNOR
SPP Market Monitoring Unit Fall 2015 State of the Market Report
Owner SPP SPP MISO M2M SPP M2M SPP SPP M2M MISO M2M SPP SPP SPP
Region Texas Panhandle Western Oklahoma East Texas SE Kansas Western Oklahoma SW Missouri Northern Arkansas Western Nebraska Texas Panhandle Oklahoma City area
Flowgate Location Osage Switch-Canyon East 115kV ftlo Bushland-Deaf Smith 230kV (SPS) Woodward-FPL Switch 138kV ftlo Tatonga-Northwest 345kV (OGE) Tubular-Dobbin 138kV ftlo Dobbin-Grimes 138kV (EES) Neosho-Riverton 161kV (WR-EDE) ftlo Neosho-Blackberry 345kV (WR-AECI) Woodward-FPL Switch 138kV ftlo Woodward Xfmr 138/69kV (OGE) Brookline Xfmr 1 345/161kV (AECI) ftlo Brookline Xfmr 2 345/161kV (SPRM) Bull Shoals Dam (SPA)-Midway (EES) 161kV ftlo Buford-Norfork (SPA) 161kV North Platte-Stockville 115kV ftlo Gentleman-Red Willow 345kV (NPPD) Sundown-Amoco 230kV ftlo Tolk-Yoakum 230kV (SPS) Arcadia-Jones KAMO 138kV ftlo Arcadia-Northwest Station 345kV (OGE)
28
2.2 Congestion by Shadow Price (12 month) Flowgate Name
Region
OSGCANBUSDEA Texas Panhandle
CONGESTION Location
Projects that may provide mitigation
Osage Switch-Canyon East 115kV ftlo Bushland-Deaf Smith 230kV (SPS)
Canyon East Sub –Randall County Interchange 115 kV line (March 2018 – Aggregate Studies)
SUNAMOTOLYOA
Sundown-Amoco 230kV ftlo Tolk-Yoakum 230kV (SPS)
WDWFPLTATNOW
Woodward-FPL Switch 138kV ftlo Woodward EHV-Northwest 345kV (OGE)
Western Oklahoma WODFPLWODXFR
1. Tuco Interchange – Yoakum 345 kV Ckt 1 (June 2020 – HPILS) 2. Amoco - Sundown 230 kV Terminal Upgrades (April 2019 - 2015 ITP10) 1. Matthewson - Tatonga 345 kV Ckt 2 (June 2017 – ITP10) 2. Elk City - Red Hills 138 kV Ckt 1 Reconductor (June 2015, ITPNT)
Woodward-FPL Switch 138kV ftlo Woodward Xfmr 138/69kV (OGE)
1. Matthewson - Tatonga 345 kV Ckt 2 (June 2017 – ITP10) 2. Woodward - Tatonga 345 kV Ckt 2 (March 2021 ITP10)
TUBDOBBENGRI
East Texas MISO M2M
Tubular-Dobbin 138kV (EES) ftlo DobbinGrimes 138kV (EES)
No projects identified at time of report publication.
NEORIVNEOBLC
SE Kansas SPP M2M
Neosho-Riverton 161kV (WR-EDE) ftlo Neosho-Blackberry 345kV (WR-AECI)
No projects identified at time of report publication.
BRKXF2BRKXF1
SW Missouri SPP M2M
Brookline Xfmr 1 (345/161) [AECI] ftlo Brookline Xfmr 2 (345/161) [SPRM]
No projects identified at time of report publication.
BULMIDBUFNOR
Northern Arkansas MISO M2M
Bull Shoals Dam (SPA)-Midway (EES) 161kV ftlo Buford-Norfork (SPA) 161kV
No projects identified at time of report publication.
NPLSTLGTLRED
Western SPP N-S Corridor
North Platte-Stockville 115kV ftlo Gentleman-Red Willow 345kV (NPPD)
1. Gentleman – Cherry Co. – Holt 345 kV (June 2018 – ITP10) 2. Thedford 345/115 kV transformer (June 2018 – HPILS)
ARCKAMARCNOR
Oklahoma City area
Arcadia-Jones KAMO 138kV ftlo ArcadiaNorthwest Station 345kV (OGE)
No projects identified at time of report publication.
SPP Market Monitoring Unit Fall 2015 State of the Market Report
29
2.3 Congestion by Interval
CONGESTION
• One way to analyze transmission congestion is to study the total incidence of intervals in which a flowgate was either breached or binding. o A breached condition is one in which the load on the flowgate exceeds the effective limit. o A binding flowgate is one in which flow over the element has reached but not exceeded its effective limit. • Figure 2.3, Congestion by Interval, shows the percent of intervals by month that had at least one breach, had only binding flowgates (but no breaches), or had no flowgates that were breached or binding (uncongested). • Congested intervals, especially intervals with breaches, have increased since the addition of the Integrated System on October 1. Reasons for this increase include increasing wind generation online, transmission and generation outages, and unaccounted flows from adjacent systems. • Note that the Fall comparison figures represent September-November for each year.
SPP Market Monitoring Unit Fall 2015 State of the Market Report
30
2.3 Congestion by Interval
CONGESTION Day Ahead
100% 80% 60% 40% 20% 0%
Sep 14
Oct 14
Nov 14
Dec 14
Jan 15
Feb 15
Intervals with Breaches
Mar 15
Apr 15
May 15
Intervals with Binding Only
Jun 15
Jul 15
Aug 15
Sep 15
Oct 15
Nov 15
Sep 15
Oct 15
Nov 15
Uncongested Intervals
Real Time
100% 80% 60% 40% 20% 0%
Sep 14
Oct 14
Nov 14
Dec 14
Jan 15
Feb 15
Intervals with Breaches FALL Comparison Day Ahead
100%
100%
80%
80%
60%
60%
40%
40%
20%
20%
0%
0%
2013
2014
2015
SPP Market Monitoring Unit Fall 2015 State of the Market Report
Mar 15
Apr 15
May 15
Intervals with Binding Only
Jun 15
Jul 15
Aug 15
Uncongested Intervals
Real Time
2013
2014
2015 31
3.1 Generation by Fuel Type
GENERATION
• Total monthly generation is shown, broken down by fuel type of resources. o Renewable includes solar, biomass and other renewable resources (not including wind and hydro) o Other includes fuel oil and miscellaneous o Gas-CC represents natural gas combined-cycle units o Gas-SC includes all other natural gas simple-cycle units • Note that the Fall comparison figures represent September-November for each year and data from 2013 is from the SPP EIS market. • Over the last two years, generation by coal-powered resources has declined by over ten percentage points, from 62.7% of total generation in 2013, to 52.1% in 2015. This decline has been covered primarily by increases in generation at nuclear (up 3.4%), wind (up 3.7%) and combined-cycle gas (up 3.3%) plants. Hydro generation increased by 2.1% over the two year period, primarily attributable to the additional hydro resources gained with the addition of the Integrated System. Generation at gas simple-cycle plants declined 1.9% from Fall 2013 to 2015.
SPP Market Monitoring Unit Fall 2015 State of the Market Report
32
3.1 Generation by Fuel Type (Real-Time)
GENERATION
30
Real-Time
Generation (GWh)
25
20
15
10
5
-
Sep 14
Oct 14
Nov 14
Other
Dec 14
Gas-SC
Jan 15
Feb 15
Gas-CC
Mar 15
Coal
Apr 15
May 15
Hydro
Jun 15
Jul 15
Renewable
Aug 15
Sep 15
Wind
Oct 15
Nov 15
Nuclear
FALL Comparison Average Monthly Generation (GW)
25 20 15 10 5 0
2013
2014
SPP Market Monitoring Unit Fall 2015 State of the Market Report
2015 33
3.1 Generation by Fuel Type by Percent (Real-Time) 80%
GENERATION
Real-Time
60%
40%
20%
0%
Sep 14
Oct 14
Nov 14
Dec 14
Jan 15
Nuclear
Feb 15
Wind
Mar 15
Apr 15
May 15
Gas-CC
Jun 15
Jul 15
Gas-SC
Aug 15
Sep 15
Oct 15
Nov 15
Coal
FALL Comparison
% Total Generation
100% 80% 60% 40% 20% 0%
2013
2014
SPP Market Monitoring Unit Fall 2015 State of the Market Report
2015 34
3.1 Generation by Fuel Type (Day-Ahead)
GENERATION
25
Generation (GWh)
20
15
10
5
-
Sep 14
Oct 14
Nov 14
Other
Dec 14
Gas-SC
Jan 15
Feb 15
Gas-CC
Mar 15
Coal
Apr 15
May 15
Hydro
Jun 15
Jul 15
Renewable
Aug 15
Sep 15
Wind
Oct 15
Nov 15
Nuclear
FALL Comparison Average Monthly Generation (GW)
20
15
10
5
0
2013
2014
SPP Market Monitoring Unit Fall 2015 State of the Market Report
2015 35
3.1 Generation by Fuel Type by Percent (Day-Ahead)
GENERATION
80%
60%
40%
20%
0%
Sep 14
Oct 14
Nov 14
Dec 14
Jan 15
Nuclear
Feb 15
Wind
Mar 15
Apr 15
May 15
Gas-CC
Jun 15
Jul 15
Gas-SC
Aug 15
Sep 15
Oct 15
Nov 15
Coal
FALL Comparison
% Total Generation
100% 80% 60% 40% 20% 0%
2013
2014
2015
SPP Market Monitoring Unit Fall 2015 State of the Market Report
36
3.2 Wind Generation and Capacity Factor (Real-Time)
GENERATION
• The following figure shows wind generation and the wind capacity factor for the past 15 months. o Note that the wind capacity factor is not directly comparable between the EIS Market and the Integrated Marketplace because resources that were pseudo-tied out of SPP were removed from the capacity calculation beginning in March. • Wind generation in the RTBM has steadily increased, with Fall generation by wind resources at 12.0% in 2013, 13.4% in 2014 and 15.8% in 2015. • Note that the Fall comparison figures represent September-November for each year and data from 2013 is from the SPP EIS market.
SPP Market Monitoring Unit Fall 2015 State of the Market Report
37
GW (Average Hourly Generation)
3.2 Wind Generation and Capacity Factor (Real-Time)
GENERATION
6
60%
5
50%
4
40%
3
30%
2
20%
1
10%
-
Sep 14
Oct 14
Nov 14
Dec 14
Jan 15
Feb 15
Mar 15
Wind Generation
Apr 15
May 15
Jun 15
Jul 15
Aug 15
Sep 15
Oct 15
Nov 15
0%
Capacity Factor
FALL Comparison 60%
Wind
15%
Capacity Factor
% Total Generation
20%
10% 5% 0%
2013
2014
SPP Market Monitoring Unit Fall 2015 State of the Market Report
2015
40%
20%
0%
2013
2014
2015
38
GW (Average Hourly Generation)
3.2 Wind Generation and Capacity Factor (Day-Ahead)
GENERATION
4
80%
3
60%
2
40%
1
20%
-
Sep 14
Oct 14
Nov 14
Dec 14
Jan 15
Feb 15
Mar 15
Wind Generation
Apr 15
May 15
Jun 15
Jul 15
Aug 15
Sep 15
Oct 15
Nov 15
0%
Capacity Factor
FALL Comparison 60%
Wind
15%
Capacity Factor
% Total Generation
20%
10% 5% 0%
2013
2014
SPP Market Monitoring Unit Fall 2015 State of the Market Report
2015
40%
20%
0%
2013
2014
2015
39
3.3 Fuel on the Margin
GENERATION
• The next figure shows the fuel types of marginal units in both the RealTime Balancing Market and the Day-Ahead Market. o Marginal units set the Locational Marginal Price in each five minute interval. o During congested periods, the market is effectively segmented into several sub-areas, each with its own marginal resource. o During non-congested periods, one resource sets the price for the entire market, thus that resource is marginal for the interval. o When there is congestion, there can be more than one marginal unit during a five-minute interval. • In the Integrated Marketplace, wind resources are on the margin more than in the EIS Market. The “other” fuel type category, consisting primarily of oil-fired and nuclear units, also shows up as being on the margin around 1-3% of all intervals. • Note that the Fall comparison figures represent September-November for each year and data from 2013 is from the SPP EIS market.
SPP Market Monitoring Unit Fall 2015 State of the Market Report
40
3.3 Fuel on the Margin (Real-Time)
GENERATION
% Intervals on Margin
100%
80%
60%
40%
20%
0%
Sep 14
Oct 14
Nov 14
Dec 14
Jan 15
Other
Feb 15
Mar 15
Gas
Apr 15
May 15
Coal
Jun 15
Jul 15
Aug 15
Sep 15
Oct 15
Nov 15
Wind
% Intervals on Margin
FALL Comparison 100% 80% 60% 40% 20% 0%
2013
2014
SPP Market Monitoring Unit Fall 2015 State of the Market Report
2015 41
3.3 Fuel on the Margin (Day-Ahead)
GENERATION
% Intervals on Margin
100%
80%
60%
40%
20%
0%
Sep 14
Oct 14
Nov 14
Dec 14
Jan 15
Other
Feb 15
Mar 15
Gas
Apr 15
May 15
Coal
Jun 15
Jul 15
Aug 15
Sep 15
Oct 15
Nov 15
Wind
% Intervals on Margin
FALL Comparison 100% 80% 60% 40% 20% 0%
2013
2014
SPP Market Monitoring Unit Fall 2015 State of the Market Report
2015 42
3.4 Ramp Rate Offered (Real-Time)
GENERATION
• The following figure shows ramp available to the system as standardized by available capacity, compared to the average online capacity. o Ramp rates play a key role in Market operations because they place limits on how quickly a unit can respond to changes in loading conditions and the need for redispatch to manage congestion. • The Ramp Availability Metric has been modified from the previous version. Previously online capacity was calculated using the nameplate capacity of resources, while currently the Economic Maximum (EcoMax) for resources is used in the calculation. • Note that the Fall comparison figures represent September-November for each year.
SPP Market Monitoring Unit Fall 2015 State of the Market Report
43
GENERATION
500
2.00
400
1.60
300
1.20
200
0.80
100
0.40
0
Sep 14
Oct 14
Nov 14
Dec 14
Jan 15
Feb 15
Mar 15
Apr 15
MW Ramp Offered per Minute
May 15
Jun 15
Jul 15
Aug 15
Sep 15
Oct 15
Nov 15
MW/min/100 MW online capacity
MW Ramp Available per Minute
3.4 Ramp Rate Offered (Real-Time)
-
MW/Min/100 MW online capacity
FALL Comparison 1.40
MW/Min/100 MW online capacity
MW Ramp Offered per Minute
400 300 200 100 0
2013
2014
SPP Market Monitoring Unit Fall 2015 State of the Market Report
2015
1.30 1.20 1.10 1.00 0.90 0.80
2013
2014
2015
44
3.5 Ramp Offered and Deficiency Intervals (Real-Time)
GENERATION
• The next figure shows the monthly average available ramp per interval along with the number of intervals with a ramp deficiency each month. o If ramp rates are too low, the market cannot respond quickly enough to manage system changes and ramp deficiencies will occur. Deficiencies result in price spikes that indicate a need for additional ramp. • Ramp deficiencies continue to show a decreasing trend on an annual basis. • Note that the Fall comparison figures represent September-November for each year.
SPP Market Monitoring Unit Fall 2015 State of the Market Report
45
GENERATION
20
500
16
400
12
300
8
200
4
100
0
Sep 14
Oct 14
Nov 14
Dec 14
Jan 15
Up Ramp Deficiency Intervals
Feb 15
Mar 15
Apr 15
May 15
Jun 15
Down Ramp Deficiency Intervals
Jul 15
Aug 15
Sep 15
Oct 15
Nov 15
MW Ramp Available per Minute
Ramp Deficiency Intervals
3.5 Ramp Offered and Deficiency Intervals (Real-Time)
0
MW Ramp Offered per Minute
FALL Comparison Ramp Deficiency Intervals
20
16 12 8 4 0
2013
2014
SPP Market Monitoring Unit Fall 2015 State of the Market Report
2015
46
3.6 Imports and Exports
GENERATION
• The following figure shows the average hourly (MW) for exports and imports for each month. • Directly comparable data is not available prior to the start of the Integrated Marketplace on March 1, 2014.
SPP Market Monitoring Unit Fall 2015 State of the Market Report
47
3.6 Imports and Exports
GENERATION
MW (Average Hourly)
2,400
1,800
1,200
600
-
Sep 14
Oct 14
Nov 14
Dec 14
Jan 15
DA Imports
Feb 15
Mar 15
RT Imports
Apr 15
May 15
Jun 15
DA Exports
Jul 15
Aug 15
Sep 15
Oct 15
Nov 15
RT Exports
FALL Comparison MW (Average Hourly)
1,600 1,200 800 400 0
2013
2014
SPP Market Monitoring Unit Fall 2015 State of the Market Report
2015
48
4.1 Day-Ahead Load Scheduling
UNIT COMMITMENT
• The next figure shows load scheduling for the peak hour. o Under-scheduling load can cause SPP to commit more expensive peaking resources in real-time in order to satisfy load. o Some real-time commitments may be made regardless of load scheduling due to the need to address reliability concerns, relieve local congestion or meet ramp demands. o Over-scheduling load can suppress real-time price signals by overstating load. • The overall average percentage of Day-Ahead load scheduling for Fall 2015 was 100.6%, which was the same for 2014.
SPP Market Monitoring Unit Fall 2015 State of the Market Report
49
4.1 Day-Ahead Load Scheduling
UNIT COMMITMENT
40
100.5% 30 100.3% GW
100.8%
100.9%
100.9%
102.1%
99.0%
100.8% 101.4%
101.1%
101.3%
Apr 15
May 15
100.4% 100.1% 101.3%
100.4%
Oct 15
Nov 15
20
10
0
Sep 14
Oct 14
Nov 14
Dec 14
Jan 15
Feb 15
Mar 15
Day-Ahead Demand
Jun 15
Jul 15
Aug 15
Sep 15
Real-Time Obligation
FALL Comparison 32
GW
24
100.6 %
100.6 %
16 8 0
2013 2014 2015
SPP Market Monitoring Unit Fall 2015 State of the Market Report
50
4.2 Average Hourly Offered Capacity (Real-Time)
UNIT COMMITMENT
• The next figure shows the Real-Time average hourly offered capacity for the peak hour. o Capacity above the line indicates that there is generally sufficient available capacity to meet peak load obligations. • Although levels fluctuate from month to month, coal and gas resources typically account for 80-90% of offered capacity during peak hours.
SPP Market Monitoring Unit Fall 2015 State of the Market Report
51
4.2 Average Hourly Offered Capacity (Real-Time)
UNIT COMMITMENT
60
50
GW
40
30
20
10
-
Sep 14
Oct 14
Nuclear
SPP Market Monitoring Unit Fall 2015 State of the Market Report
Nov 14 Wind
Dec 14
Jan 15
Renewable
Feb 15
Mar 15 Hydro
Apr 15 Coal
May 15
Jun 15 Gas
Jul 15 Other
Aug 15
Sep 15
Oct 15
Nov 15
RT Peak Load Obligation
52
4.3 Average Peak Hour Capacity Overage (Real-Time)
UNIT COMMITMENT
• The following figure shows the Real-Time Average Peak Hour Capacity Overage. o SPP calculates the amount of capacity overage required for the Operating Day to ensure that unit commitment is sufficient to reliably serve load in Real-Time while maintaining the Operating Reserve requirements. o This is calculated as: Economic Maximum – Load – Net Scheduled Interchange – (Regulation Up + Spinning Reserves + Supplemental Reserves) • The average peak hour capacity overage for real-time increased by just over 61% from Fall 2014 to 2015.
SPP Market Monitoring Unit Fall 2015 State of the Market Report
53
4.3 Average Peak Hour Capacity Overage (Real-Time)
UNIT COMMITMENT
5,000
4,000
MW
3,000
2,000
1,000
0
Sep 14
Oct 14
Nov 14
Dec 14
Jan 15
Feb 15
Mar 15
Apr 15
May 15
Jun 15
Jul 15
Aug 15
Sep 15
Oct 15
Nov 15
Economic Maximum – Load – Net Scheduled Interchange – (Regulation Up + Spinning Reserves + Supplemental Reserves) 5,000
4,215
4,000
MW
3,000
2,615
2,000 1,000 0
2013
2014
2015
SPP Market Monitoring Unit Fall 2015 State of the Market Report
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5.1 Virtual Transactions
VIRTUAL ENERGY
• Virtual trading in the Day-Ahead Market facilitates convergence between the Day-Ahead and Real-Time prices. o Virtual trading helps improve the efficiency of the Day-Ahead Market and moderates market power. • Virtual transactions scheduled in the Day-Ahead Market are settled in the Real-Time Market. o Virtual demand bids are profitable when the Real-Time energy price is higher than the Day-Ahead price. o Virtual supply offers are profitable when the Day-Ahead energy price is higher than the Real-Time price. • The following figure shows cleared and uncleared virtual demand bids and supply offers. o Uncleared demand bids and supply offers, and cleared supply offers have shown a marked increase from Fall 2014 to Fall 2015. Cleared demand binds have only had a slight increase from 2014 to 2015.
SPP Market Monitoring Unit Fall 2015 State of the Market Report
55
5.1 Virtual Transactions
VIRTUAL ENERGY
Average Hourly MWh
3,000Virtual trading in the Day-Ahead Market facilitates convergence between the Day-Ahead and Real-Time prices.
Demand Bids
2,500 2,000 1,500 1,000
Virtual demand bids are profitable when the Real-Time energy price is higher than the Day-Ahead price.
500 0
Virtual supply offers are profitable when the Day-Ahead energy price is higher than the Real-Time price. Sep 14
Oct 14
Nov 14
Dec 14
Jan 15
Feb 15
Mar 15
Cleared Demand Bids
Average Hourly MWh
5,000
Apr 15
May 15
Jun 15
Jul 15
Aug 15
Sep 15
Oct 15
Nov 15
Jul 15
Aug 15
Sep 15
Oct 15
Nov 15
Uncleared Demand Bids
Supply Offers
4,000 3,000 2,000 1,000 0
Sep 14
Oct 14
Nov 14
Dec 14
Jan 15 Feb 15 Mar 15 Cleared Supply Offers
Apr 15 May 15 Jun 15 Uncleared Supply Offers
2,000
3,600
Demand Bids
Average Hourly MWh
Average Hourly MWh
FALL Comparison 1,600 1,200 800 400 0
2013
2014
SPP Market Monitoring Unit Fall 2015 State of the Market Report
2015
Supply Offers
2,700 1,800 900 0
2013
2014
2015 56
5.2 Cleared Virtual Transactions as Percentage of Reported Load
VIRTUAL ENERGY
• Virtual trading in the Day-Ahead Market facilitates convergence between the Day-Ahead and Real-Time prices. o Cleared Virtual Bids as a percentage of Reported Load is averaging just under 3% since the start of the Integrated Marketplace. o Cleared Virtual Offers as a percentage of Reported Load is averaging just over 4% since the start of the Integrated Marketplace. o The average cleared virtual transactions as a percent of load since the start of the Integrated Marketplace is just over 7%. • Since the start of the Integrated Marketplace, November 2015 had the largest amount of Virtual transactions at 10.76% of reported load.
SPP Market Monitoring Unit Fall 2015 State of the Market Report
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5.2 Cleared Virtual Transactions as Percentage of Reported Load
Cleared Virtuals as % of STLF
12%
VIRTUAL ENERGY
Virtual trading in the Day-Ahead Market facilitates convergence between the Day-Ahead and Real-Time prices.
10%
Virtual demand bids are profitable when the Real-Time energy price is higher than the Day-Ahead price.
8%
Virtual supply offers are profitable when the Day-Ahead energy price is higher than the Real-Time price. 6% 4% 2% 0%
Sep 14
Oct 14
Nov 14
Dec 14
Jan 15
Feb 15
Mar 15
Cleared Virtual Bids as % of Load
Apr 15
May 15
Jun 15
Jul 15
Aug 15
Sep 15
Oct 15
Nov 15
Cleared Virtual Offers as % of Load
Cleared Virtuals as % of STLF
12% 10% 8% 6% 4% 2% 0%
2013
2014
SPP Market Monitoring Unit Fall 2015 State of the Market Report
2015 58
5.3 Virtual Transactions by Participant Type
VIRTUAL ENERGY
• Virtual trading in the Day-Ahead Market facilitates convergence between the Day-Ahead and Real-Time prices. o Participants with physical assets (resources and/or load) often place transactions in order to hedge physical obligations. o In contrast, financial-only participants generally arbitrage prices. • The vast majority of Virtual demand bids are placed by Financial Only participants. • While the number of virtual demand bids by resource/load owners has remained negligible, demand bids by financial-only participants has increased by just over 30% from Fall 2014 to Fall 2015. • For virtual supply offers, offers by financial-only participants has increased nearly 60% from Summer 2014 to Summer 2015, while offers by resource/load owners has decreased nearly 80% in the same period.
SPP Market Monitoring Unit Fall 2015 State of the Market Report
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5.3 Virtual Transactions by Participant Type 1,200 1,000
VIRTUAL ENERGY
Virtual trading in the Day-Ahead Market facilitates convergence between the Day-Ahead and Real-Time prices. Demand Bids
GWh
800 600 400
Virtual demand bids are profitable when the Real-Time energy price is higher than the Day-Ahead price.
200 0
Virtual supply offers are profitable when the Day-Ahead energy price is higher than the Real-Time price. Sep 14
Oct 14
Nov 14
Dec 14 Jan 15 Feb 15 Mar 15 Financial Only Owners Demand Bids
1,200
Apr 15 May 15 Jun 15 Jul 15 Aug 15 Resource/Load Owner Demand Bids
Sep 15
Oct 15
Nov 15
Sep 15
Oct 15
Nov 15
Supply Offers
1,000 GWh
800 600 400 200 0
800
Sep 14
Oct 14
Nov 14
Dec 14 Jan 15 Feb 15 Mar 15 Financial Only Owners Supply Offers 800
Demand Bids
400
400 200
200 0
Supply Offers
600 GWh
GWh
600
Apr 15 May 15 Jun 15 Jul 15 Aug 15 Resource/Load Owner Supply Offers
2013
2014
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2015
0
2013
2014
2015 60
5.4 Virtual Transactions by Location Type
VIRTUAL ENERGY
• The next figure summarizes virtual transactions by location type – o hub, o interface, o resource or o load. • Since the start of the Integrated Marketplace, the majority of virtual transactions are made at resources, with the fewest transactions at external interfaces.
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5.4 Virtual Transactions by Location Type (MW) 1,200
VIRTUAL ENERGY
Virtual trading in the Day-Ahead Market facilitates convergence between the Day-Ahead and Real-Time prices.
1,000
Virtual demand bids are profitable when the Real-Time energy price is higher than the Day-Ahead price.
Thousands
800
Virtual supply offers are profitable when the Day-Ahead energy price is higher than the Real-Time price. 600
400
200
0
Sep 14
Oct 14
Nov 14
Dec 14
Jan 15
Feb 15 Hub
Mar 15 Interface
Apr 15 Load
May 15
Jun 15
Jul 15
Aug 15
Sep 15
Oct 15
Nov 15
Resource
1,000
Thousands
800 600 400 200 0
2013
2014
2015
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5.5 Virtual Profits and Losses
VIRTUAL ENERGY
• The next figure summarizes the monthly profitability of virtual demand bids and supply offers. • Gross virtual profits for the most recent twelve months of the market totaled just over $80 million, while gross virtual losses totaled just over $60 million. • Since the start of the Integrated Marketplace, every month had a net profit from virtual transactions, with the exception of May 2014, which had a net loss of just over $700,000.
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5.5 Virtual Profits and Losses $15
VIRTUAL ENERGY
Virtual trading in the Day-Ahead Market facilitates convergence between the Day-Ahead and Real-Time prices.
$10
Virtual demand bids are profitable when the Real-Time energy price is higher than the Day-Ahead price.
Millions
$5
Virtual supply offers are profitable when the Day-Ahead energy price is higher than the Real-Time price. $0
-$5
-$10
-$15
Sep 14
Oct 14
Nov 14
Dec 14
Jan 15
Feb 15
Total Virtual Profit
Mar 15
Apr 15
May 15
Total Virtual Loss
Jun 15
Jul 15
Aug 15
Sep 15
Oct 15
Nov 15
Net Virtual Profit/Loss
$15 $10 Millions
$5 $0 -$5
-$10 -$15
2013
2014
2015
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6.1 TCR/ARR Funding Summary
TRANSMISSION CONGESTION RIGHTS
• TCR/ARR funding is derived as follows: 1. Day-ahead revenue is collected daily 2. TCR holders are paid daily based on awarded TCR MW and Day-ahead clearing prices a. Uplift is charged daily b. Surpluses are redistributed Monthly and Annually 3. TCR revenue is collected daily based on TCR MW and TCR ACPs (consistent through month/season) 4. ARR holders are paid daily based on ARR MW and TCR ACPs (consistent through month/season) a. Uplift is charged daily b. Surpluses are redistributed Monthly and Annually
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Millions
6.1 TCR Funding Summary
TRANSMISSION CONGESTION RIGHTS
$60
120%
$50
100%
$40
80%
$30
60%
$20
40%
$10
20%
$0
0%
-$10
Sep 14
Oct 14
Nov 14
DA Revenue
SPP Market Monitoring Unit Fall 2015 State of the Market Report
Dec 14
Jan 15
TCR Funding
Feb 15
Mar 15
Apr 15
TCR Uplift
May 15 Jun 15
Jul 15
Funding Percent
Aug 15
Sep 15
Oct 15
Nov 15
-20%
Cumulative Funding Percent
66
Millions
6.2 ARR Funding Summary
TRANSMISSION CONGESTION RIGHTS
$70
140%
$60
120%
$50
100%
$40
80%
$30
60%
$20
40%
$10
20%
$0
Sep 14
Oct 14
Nov 14
DA Revenue
SPP Market Monitoring Unit Fall 2015 State of the Market Report
Dec 14
Jan 15
TCR Funding
Feb 15
Mar 15
Apr 15
TCR Uplift
May 15 Jun 15
Jul 15
Funding Percent
Aug 15
Sep 15
Oct 15
Nov 15
0%
Cumulative Funding Percent
67
7.1 Make Whole Payments
UPLIFT
• A Make Whole Payment is paid to a generator when the market commits a generator with offered costs exceeding the market revenue for the commitment period. o The Day-Ahead Make Whole Payment applies to commitments from the Day-Ahead Market. o The RUC Make Whole Payment applies to commitments made in the Day Ahead RUC and Intra-Day RUC processes. • Day-Ahead Make Whole Payments are typically less frequent and lesser in magnitude than in the RUC Make Whole Payments in the Real-Time Market. • As expected, the majority of the RUC Make Whole Payments are paid to gas resources. • During October and November a high amount of Make Whole Payments were made to coal resources in the Day-Ahead Market due to local commitments.
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7.1 Make Whole Payments
UPLIFT Day-Ahead
$9
Millions
$6
$3
$0
Sep 14
Oct 14
Nov 14
Wind
Dec 14
Jan 15
Renewable
Feb 15
Mar 15
Nuclear
Apr 15
Hydro
May 15
Coal
Jun 15
Jul 15
Gas-CC
Aug 15
Gas-SC
Sep 15
Oct 15
Nov 15
Other
RUC (Real-Time)
$9
Millions
$6
$3
$0
Sep 14
Oct 14
Nov 14
Wind
SPP Market Monitoring Unit Fall 2015 State of the Market Report
Dec 14
Jan 15
Renewable
Feb 15
Nuclear
Mar 15
Apr 15
Hydro
May 15
Coal
Jun 15
Jul 15
Gas-CC
Aug 15
Gas-SC
Sep 15
Oct 15
Nov 15
Other
69
7.2 Make Whole Payment - Distribution Rate
UPLIFT
• The Make Whole Payment Distribution Charge is applied to Asset Owners that receive benefits from units committed in the Day-Ahead and Real-Time Markets. o The Day-Ahead Make Whole Payment Distribution Amount is an hourly charge or credit based on a daily allocation. o The total of all Make Whole Payments paid to generation resources is spread among all Asset Owners according to the ratio of the load’s contribution relative to a specific market. o For the Day-Ahead market, the distribution rate is the sum of all DA Market Make Whole Payments for the day, divided by the total DA Market withdrawals. o For the Real-Time Market, the distribution rate is the sum of RT Make Whole Payments for the day divided by the total RT Market deviation.
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7.2 Make Whole Payment - Distribution Rate Day-Ahead
$/MWh
$3
$2
$1
$0
Sep 14
Oct 14
Nov 14
Dec 14
Jan 15
Feb 15
Mar 15
Apr 15
May 15
Jun 15
Jul 15
Aug 15
Sep 15
Oct 15
Nov 15
Apr 15
May 15
Jun 15
Jul 15
Aug 15
Sep 15
Oct 15
Nov 15
RUC
$3
$/MWh
UPLIFT
$2
$1
$0
Sep 14
Oct 14
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Nov 14
Dec 14
Jan 15
Feb 15
Mar 15
71
7.3 Day-Ahead Must-Offer Penalty
UPLIFT
• Each market participant with registered load is required to satisfy the must offer obligation for each asset owner associated with that registered load. • A market participant is in compliance if: o The market participant has offered its available resources for an asset owner with a commitment status of Market, Self, or Reliability; or o The market participant has net resource capacity for that asset owner greater than or equal to 90% of its load for that asset owner. • If a Market Participant is not in compliance with the must-offer obligation, it will be assessed a Day-Ahead Must-Offer (DAMO) penalty. o The penalty amount is equal to the Day-Ahead Market LMP associated with the withheld capacity. o When Must-Offer Penalty revenues are collected, the revenues are distributed to the Market Participants for an Asset Owner on a pro-rata basis for that Asset Owner's offered Resources. The Market Participant who failed the obligation does not receive a payment. • Note that in Figure 7.3, figures shown are from the most recent settlement statements available for that time period and are subject to resettlement. • Overall, the Day-Ahead Must-Offer failures continue to represent a very small portion of the Day-Ahead Market. SPP Market Monitoring Unit Fall 2015 State of the Market Report
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7.3 Day-Ahead Must-Offer Penalty
UPLIFT
$240
Thousands
$180
$120
$60
$0
Oct 14
Nov 14
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Dec 14
Jan 15
Feb 15
Mar 15
Apr 15
May 15
Jun 15
Jul 15
Aug 15
Sep 15
Oct 15
Nov 15
73
7.4 Revenue Neutrality Uplift (RNU)
UPLIFT
• Revenue Neutrality Uplift (RNU) ensures settlement payments/receipts for each hourly settlement interval equal zero. o Positive RNU - SPP receives insufficient revenue and collects from market participants. o Negative RNU - SPP receives excess revenue, which must be credited back to market participants. • Revenue neutrality uplift is comprised by the following components: o DA Revenue Inadequacy o RT Revenue Inadequacy o RT Out of Merit Energy (OOME) Make Whole Payment o RT Regulation Deployment Adjustment o RT Joint Owned Asset (JOA) Adjustment o RT Inadvertent Interchange Adjustment o RT Congestion Adjustment • Figures shown are from the most recent settlement statements available for that time period and are subject to change due to resettlement.
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7.4 Revenue Neutrality Uplift (RNU)
UPLIFT
$5,000 $4,000
Thousands
$3,000 $2,000 $1,000 $0 -$1,000 -$2,000 -$3,000
Sep 14
Oct 14
Nov 14
Dec 14
Jan 15
Feb 15
Mar 15
Apr 15 May 15 Jun 15
Jul 15
Aug 15
Sep 15
Oct 15
Nov 15
Total Marketplace RNU
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7.4 Revenue Neutrality Uplift (RNU) in thousands $
DA Revenue Inadequacy RT Revenue Inadequacy
UPLIFT
Sep 14 Oct 14 Nov 14 Dec 14 Jan 15 Feb 15 Mar 15 Apr 15 May 15 Jun 15 Jul 15 Aug 15 Sep 15 Oct 15 Nov 15 0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
110
88
132
68
73
47
174
14
72
39
27
6
61
62
26
RT OOME MWP
39
7
158
4
4
3
21
50
15
41
7
131
16
125
34
RT Regulation Deployment Adj
38
78
18
122
-20
-72
-127
-51
44
48
127
62
52
42
35
0
0
0
0
0
0
-4,337
-1,873
-1,744
254
-71
217
-378
38
892
RT Congestion Adj
2,771
2,034
1,673
1,181
3,458
279
1,149
5,299
3,046
1,516
2,253
1,935
1,918
3,549
2,054
SUBTOTAL
2,958
2,207
1,982
1,376
3,514
256
-3,120
3,439
1,432
1,898
2,344
2,350
1,670
3,817
3,042
907
-596
-264
-632
44
-23
-348
-817
-552
-675
-1,066
-554
-287
-712
-404
2,050
2,803
2,245
2,009
3,470
279
-2,772
4,256
1,984
2,573
3,410
2,905
1,957
4,528
3,446
RT JOA Adj
Less RT Net Inadvertent Adj TOTAL RNU
* This table is based on the latest available settlements data and is subject to change due to resettlement
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7.5 Market to Market
UPLIFT
• Market to Market is a coordinated exchange of cost of re-dispatch (Shadow Prices), requested market flow relief, and control indicators between SPP and MISO. o This coordination allows for the neighboring market (non-monitoring RTO) to provide relief to congestion if it can do so more economically o Market to Market payments are made based on the non-monitoring RTO’s (NMRTO) market flow against their Firm Flow Entitlement (FFE) and the Shadow Price during the congestion o NMRTO market flow above FFE = NMRTO pays MRTO o NMRTO market flow below FFE = MRTO pays NMRTO • The first graph shows totals by month. • The second graph shows totals by constraint for the Summer 2015 period.
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7.5 Market to Market
UPLIFT
$5,000 $4,000
Thousands
$3,000 $2,000 $1,000 $0 -$1,000 -$2,000
Sep 14
Oct 14
Nov 14
Dec 14
Jan 15
Feb 15
Mar 15
Receipts (MISO -> SPP)
SPP Market Monitoring Unit Fall 2015 State of the Market Report
Apr 15 May 15 Jun 15
Jul 15
Payments (SPP -> MISO)
Aug 15
Sep 15
Oct 15
Nov 15
Net
78
7.5 Market to Market (September-November 2015)
UPLIFT
$1,000 $500
Thousands
$0 -$500 -$1,000 -$1,500 -$2,000
Receipts (MISO --> SPP)
Payments (SPP --> MISO)
* Only includes those flowgates with over $50,000 in net Market to Market payments.
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7.6 Regulation Mileage Make Whole Payments
UPLIFT
• On March 1, 2015, SPP implemented its Regulation Compensation market design in compliance with FERC Order 755. It includes payment to market participants based on changes in energy output for regulation deployment. • During March 2015, SPP cleared more regulation mileage than necessary with a regulation mileage factor of 1.0 for both regulation up and down. The factor has been adjusted to a more realistic value, averaging near 0.2, since March. The lower factor results in fewer unused mileage make whole payments.
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7.6 Regulation Mileage Make Whole Payments
Thousands
$360
1.20
Regulation Up
$300
1.00
$240
0.80
$180
0.60
$120
0.40
$60
0.20
$0
0.00
Sep 14
Oct 14
Nov 14 Dec 14
Jan 15
Feb 15 Mar 15 Apr 15 May 15 Jun 15
DA Unused Mileage MWP $360
Thousands
UPLIFT
Jul 15
RT Unused Mileage MWP
Aug 15 Sep 15
Oct 15
Nov 15
Regulation Mileage Factor 1.20
Regulation Down
$300
1.00
$240
0.80
$180
0.60
$120
0.40
$60
0.20
$0
Sep 14
Oct 14
Nov 14 Dec 14
Jan 15
Feb 15 Mar 15 Apr 15 May 15 Jun 15
DA Unused Mileage MWP SPP Market Monitoring Unit Fall 2015 State of the Market Report
RT Unused Mileage MWP
Jul 15
Aug 15 Sep 15
Oct 15
Nov 15
0.00
Regulation Mileage Factor 81
ACRONYMS
ABS ACP AO ARR BA CC DA DAMKT DAMO DVER EIS GW GWh IS JOA LIP LMP M2M MCC MCP MEC MLC
Absolute Auction Clearing Price Asset Owner Auction Revenue Rights Balancing Authority Combined-Cycle (Gas) Day-Ahead Day-Ahead Market Day-Ahead Must Offer Dispatchable Variable Energy Resource Energy Imbalance Service Gigawatt Gigawatt-hour Integrated System Joint Owned Asset Locational Imbalance Price Locational Marginal Price Market-to-Market Marginal Congestion Component Market Clearing Price Marginal Energy Component Marginal Loss Component
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ACRONYMS
MP MW MWG MTLF MWh NSI OOME PEPL RNU RT RTBM RUC SC SCED SCUC STLF TCR TLR URD VER
Market Participant Megawatt Market Working Group Mid-Term Load Forecast Megawatt-hour Net Scheduled Interchange Out of Merit Energy Panhandle Eastern Pipeline Revenue Neutrality Uplift Real-Time Real-Time Balancing Market Reliability Unit Commitment Simple-Cycle (Gas) Security Constrained Economic Dispatch Security Constrained Unit Commitment Short-Term Load Forecast Transmission Congestion Rights Transmission Loading Relief Uninstructed Resource Deviation Variable Energy Resource
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MARKET PARTICIPANTS AECC AEPM_X BEPM CHAN EDEP FREM GRDX GSEC HMMU INDN KBPU KCPS KMEA KPP LESM MEAN MECB MEUC MIDW MRES NSPP NWPS OGE OMPA OPPM REMC SEPC SPSM TEA TNSK UGPM WFES WRGS
Arkansas Electric Cooperative Corporation American Electric Power Basin Electric Power Cooperative City of Chanute (KS) Empire District Electric Company City of Fremont (NE) Grand River Dam Authority Golden Spread Electric Cooperative Harlan (IA) Municipal Utilities City of Independence (MO) Board of Public Utilities (Kansas City, KS) Kansas City Power & Light Company Kansas Municipal Energy Agency Kansas Power Pool Lincoln Electric System Municipal Energy Agency of Nebraska MidAmerican Energy Company Missouri Joint Municipal EUC Midwest Energy Missouri River Energy Services NSP Energy Marketing Northwestern Energy Oklahoma Gas and Electric Company Oklahoma Municipal Power Authority Omaha Public Power District Rainbow Energy Marketing Corporation Sunflower Electric Power Corporation Southwestern Public Service Company The Energy Authority Tenaska Power Services Company Western Area Power Administration – UGP Marketing Western Farmers Electric Cooperative Westar Energy, Inc.
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ASSET OWNERS 1073 AECC AEPM BEPM CHAN COWP CWEP EDEP EMP1_X EMP2_X EMP3_X EUDO_X FCU_X FREM GATE_X GRDX GSEC HMMU INDN KBPU KCPS KMEA KN01 KPP LESM MEAN MEUC MIDW MMPA_X
City of Malden (MO) Board of Public Works Arkansas Electric Cooperative Corporation American Electric Power Basin Electric Power Cooperative City of Chanute (KS) City of West Plains (MO) Board of Public Works Carthage (MO) Water and Electric Plant Empire District Electric Company Kansas Municipal Energy Agency Kansas Municipal Energy Agency Kansas Municipal Energy Agency City of Eudora (KS) Electric Utility Falls City (NE) Utilities City of Fremont (NE) Gateway Grand River Dam Authority Golden Spread Electric Cooperative Harlan (IA) Municipal Utilities City of Independence (MO) Board of Public Utilities (Kansas City, KS) Kansas City Power & Light Company Kansas Municipal Energy Agency Kennett (MO) Board of Public Works Kansas Power Pool Lincoln Electric System Municipal Energy Agency of Nebraska Missouri Joint Municipal EUC Midwest Energy Minnesota Municipal Power Agency
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ASSET OWNERS MUMZ_X NCU_X NELI_X NMCA_X NPPM NWMT_X OGE OMPA OPPM OTP_X PARL PBEL PLWC REMC SEPC SMGT_X SPRM SPSM TEAC TEAN TNGI_X TNHP_X TNHU_X TNSK UCU WFES WRGS
Missouri River Energy Services, UMZ Load Nebraska City (NE) Utilities City of Neligh (NE) Utilities North Iowa Municipal Electric Cooperative Association Nebraska Public Power District Northwestern Energy Oklahoma Gas and Electric Company Oklahoma Municipal Power Authority Omaha Public Power District Otter Tail Power Company City of Piggott (AR) Municipal Light, Water and Sewer City of Poplar Bluff (MO) Municipal Utilities Paragould (AR) Light & Water Commission Rainbow Energy Marketing Corporation Sunflower Electric Power Corporation Southern Montana Electric Generation & Transmission Cooperative City Utilities of Springfield (MO) Southwestern Public Service Company City Utilities of Springfield (MO) Nebraska Public Power District City of Grand Island (NE) Utilities Heartland Consumers Power District Hastings (NE) Utilities Tenaska Power Services Company KCP&L Greater Missouri Operations Company Western Farmers Electric Cooperative Westar Energy, Inc.
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