State of the Market Report Fall 2015 - Southwest Power Pool

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

2

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


3

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.


4

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

6

1.3 Price Contour Maps Day-Ahead (September-November 2015) Day-Ahead Off-Peak


PRICES

Day-Ahead On-Peak

7

1.3 Price Contour Maps Real-Time (September-November 2015) Real-Time Off-Peak


PRICES

Real-Time On-Peak

8

1.3 Price Contour Maps Day-Ahead (December 2014-November 2015) Day-Ahead Off-Peak


PRICES

Day-Ahead On-Peak

9

1.3 Price Contour Maps Real-Time (December 2014-November 2015) Real-Time Off-Peak


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.


11

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%


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.


13

$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 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 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.


16

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 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 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.


19

1.7 Trading Hub Prices

PRICES

$50

$40

$/MWh

$30

$20

$10

$0

Sep 14

Oct 14

Nov 14

Dec 14

North DAMKT


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.


21

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


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


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


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.


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.


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


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


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)


BRKXF2BRKXF1

SW Missouri SPP M2M

Brookline Xfmr 1 (345/161) [AECI] ftlo Brookline Xfmr 2 (345/161) [SPRM]


BULMIDBUFNOR

Northern Arkansas MISO M2M

Bull Shoals Dam (SPA)-Midway (EES) 161kV ftlo Buford-Norfork (SPA) 161kV


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)



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.


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


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.


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


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


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


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


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.


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


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


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.


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


FALL Comparison 100% 80% 60% 40% 20% 0%

2013

2014


2015 41

3.3 Fuel on the Margin (Day-Ahead)

GENERATION


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


FALL Comparison 100% 80% 60% 40% 20% 0%

2013

2014


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.


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


400 300 200 100 0

2013

2014


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.


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


FALL Comparison Ramp Deficiency Intervals

20

16 12 8 4 0

2013

2014


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.


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


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.


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


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.


51

4.2 Average Hourly Offered Capacity (Real-Time)

UNIT COMMITMENT

60

50

GW

40

30

20

10

-

Sep 14

Oct 14

Nuclear


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.


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


54

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.


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


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.


57

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%


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


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.


59

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


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


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.


61

5.4 Virtual Transactions by Location Type (MW) 1,200

VIRTUAL ENERGY


1,000


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


62

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.


63

5.5 Virtual Profits and Losses $15

VIRTUAL ENERGY


$10


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


64

6.1 TCR/ARR Funding Summary


• 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


65

Millions

6.1 TCR Funding Summary


$60

120%

$50

100%

$40

80%

$30

60%

$20

40%

$10

20%

$0

0%

-$10

Sep 14

Oct 14

Nov 14

DA Revenue


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


$70

140%

$60

120%

$50

100%

$40

80%

$30

60%

$20

40%

$10

20%

$0

Sep 14

Oct 14

Nov 14

DA Revenue


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.


68

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


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.


70

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


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

72

7.3 Day-Ahead Must-Offer Penalty

UPLIFT

$240

Thousands

$180

$120

$60

$0

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

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.


74

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


75

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


76

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.


77

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)


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.


79

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.


80

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


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


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


82

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


83

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.


84

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


85

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.


86