2010 State of the Market

Published:  May 10, 2011

 SPP Market Monitoring Unit
 

Table of Contents

Disclaimer .....................................................................................................................................................8

Executive Summary .....................................................................................................................................9

A. Purpose .......................................................................................................................................9

B. Overview of the SPP Footprint ..................................................................................................9

Electricity Supply and Demand ................................................................................................................ 9

Generation Interconnection .................................................................................................................... 10

Generation and Transmission Outages ................................................................................................... 10

C. EIS Market Results...................................................................................................................10

Market Activity ...................................................................................................................................... 10

Market Prices ......................................................................................................................................... 10

Revenue Adequacy (Cost Recovery Determination) ............................................................................. 11

Fuel Type ............................................................................................................................................... 11

Market Participation ............................................................................................................................... 12

Market Power Mitigation ....................................................................................................................... 13

Market Power Monitoring ...................................................................................................................... 13

Revenue Neutrality Uplift ...................................................................................................................... 13

D. Energy Delivery .......................................................................................................................14

Transmission Owner Revenue ............................................................................................................... 14

Transmission Service Requests .............................................................................................................. 14

Transmission Congestion ....................................................................................................................... 14

Transmission Outages ............................................................................................................................ 14

Transmission Investment........................................................................................................................ 15

I. Overview of SPP Footprint .............................................................................................................16

A. Brief Overview of SPP .............................................................................................................16

SPP’s Location ....................................................................................................................................... 17

SPP Membership .................................................................................................................................... 18

SPP Balancing Authorities ..................................................................................................................... 19

B. Electricity Demand in the SPP Region ....................................................................................20

System Peak Demand ............................................................................................................................. 20

Market Participant Peak and Total Demand........................................................................................... 21

System Demand Profile .......................................................................................................................... 23

Load Duration Curve .............................................................................................................................. 24

Summary and Conclusions ..................................................................................................................... 25
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C. Generation – The Supply of Electricity ....................................................................................26

Capacity in the SPP Market Region ....................................................................................................... 26

Resource Margin .................................................................................................................................... 27

Capacity Additions in 2010 .................................................................................................................... 27

Implied Heat Rate .................................................................................................................................. 28

Summary and Conclusions ..................................................................................................................... 29

D. Transmission – The Bridge between Supply and Demand ......................................................30

Transmission System Characteristics ..................................................................................................... 30

Inter-grid Connection Points .................................................................................................................. 31

Summary and Conclusions ..................................................................................................................... 31

II. EIS Market Activity................................................................................................................................32

A. Brief Overview of the EIS Market ...........................................................................................32

B. Market Activity ........................................................................................................................32

EIS Sales and Purchases ......................................................................................................................... 32

C. Market Prices............................................................................................................................34

Regional Price Comparison .................................................................................................................... 34

SPP and Gas Price Comparison ............................................................................................................. 36

Average Hourly Prices ........................................................................................................................... 37

Market Participant Price Comparisons ................................................................................................... 39

Price Volatility ....................................................................................................................................... 40

Price Spread ........................................................................................................................................... 41

Average Monthly Prices ......................................................................................................................... 42

Interval Price Excursions ....................................................................................................................... 43

Re-pricing Occurrence ........................................................................................................................... 44

2010 Price Contour Map ........................................................................................................................ 45

Principal Congested Flowgates .............................................................................................................. 46

Summary and Conclusions ..................................................................................................................... 47

D. Revenue Adequacy (Cost Recovery Determination) ...............................................................48

E. Fuel Type ..................................................................................................................................50

Generation by Fuel Type (percentages) ................................................................................................. 50

Generation by Fuel Type (graphical) ..................................................................................................... 51

Generation on the Margin ...................................................................................................................... 52

Wind Capacity and Generation .............................................................................................................. 53

F. Market Participation .................................................................................................................54

Dispatchable Range ................................................................................................................................ 54
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Ramp Rates ............................................................................................................................................ 55

Ramp and Capacity ................................................................................................................................ 56

Status Type Utilization ........................................................................................................................... 57

Generation by Status Type ..................................................................................................................... 57

G. Market Power Measurement and Mitigation ...........................................................................58

Offer Cap ................................................................................................................................................ 59

Herfindahl-Hirschman Index (Market Participant Capacity) ................................................................. 61

Herfindahl-Hirschman Index (Uncommitted Capacity) ......................................................................... 61

Wholesale Uncommitted Capacity ......................................................................................................... 62

H. Revenue Neutrality Uplift ........................................................................................................63

RNU Results ........................................................................................................................................... 65

All-in Price ............................................................................................................................................. 66

Net versus Absolute EIS Payments Uplift ............................................................................................. 67

III. Energy Delivery ................................................................................................................................68

A. Transmission Service ...............................................................................................................68

Transmission Owner Revenue ............................................................................................................... 69

Transmission Service Requests by Year ................................................................................................ 70

Transmission Service Requests by Status .............................................................................................. 71

Approved and Refused Transmission Service Requests ........................................................................ 72

B. Transmission Congestion .........................................................................................................73

Flowgate Congestion by Time (percentages) ......................................................................................... 74

Flowgate Congestion by Time (graphical) ............................................................................................. 75

Incidence of Flowgate Congestion.................................................................................................76

Breached Flowgates ............................................................................................................................... 76

Binding Flowgates ................................................................................................................................. 77

Constrained Flowgates by Time ............................................................................................................. 78

Constrained Flowgates by Shadowprice ................................................................................................ 79

C. Transmission Outages ..............................................................................................................80

Transmission Outage Days..................................................................................................................... 80

Transmission Outage Days by Month .................................................................................................... 81

Transmission Outage Days by Balancing Authority .............................................................................. 82

Relative Repair Time for Transmission Outages ................................................................................... 83

D. Generator Outages ....................................................................................................................84

E. Generation Interconnection (2010) ............................................................................................85

F. Transmission Investment ..........................................................................................................87
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IV. Market Developments ......................................................................................................................88

A. Integrated Marketplace Design Issues .....................................................................................88

MMU Supports ....................................................................................................................................... 88

MMU Concerns ...................................................................................................................................... 88

Integrated Marketplace Design Status Update (April 2011) .................................................................. 91

B. SPP Interregional Issues ...........................................................................................................92

Improvement of Market Flow Calculations ........................................................................................... 93

Improvement of Coordinated Planning .................................................................................................. 93

Comprehensive Cost Allocation Methodology ...................................................................................... 93

Parallel Flow Visualization Methodology .............................................................................................. 93

Summary and Conclusions ..................................................................................................................... 94

C. Developments in Natural Gas Markets ....................................................................................95

Shale Gas Development ......................................................................................................................... 95

Pipeline Construction ............................................................................................................................. 95

Conclusions and Concerns ..................................................................................................................... 95

D. SPP Congestion Management Changes ...................................................................................97

Transmission Loading Relief (TLR)/Congestion Management Event (CME) Procedure Review ........ 97

Early Results of CME Implementation .................................................................................................. 97

2010 Conclusions and Recommendations ..................................................................................................99

Definitions of Select Terms .........................................................................................................................102

Common Acronyms .....................................................................................................................................103

 
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List of Figures 

Figure I.1 NERC Interconnections .............................................................................................................17

Figure I.2 Members as of December 31, 2010 ...........................................................................................18

Figure I.3 Map of SPP Balancing Authorities ...........................................................................................19

Figure I.4 Monthly Peak Electric Energy Demand for the SPP Market Region (MW) .......................20

Figure I.5 Market Participant Demand and Electric Energy Usage in 2010 .........................................21

Figure I.6 Total System Load (MWh) ........................................................................................................22

Figure I.7 Daily Minimum and Maximum Electric Energy Demand 2008 – 2010 ................................23

Figure I.8 Electric Load Duration Curve 2008 -2010 ...............................................................................24

Figure I.9 Current Installed Generation Capacity by Balancing Authority ..........................................26

Figure 1.10 Resource Margin by Year .......................................................................................................27

Figure I.11 Capacity Additions by Fuel Type ...........................................................................................27

Figure I.12 Implied Heat Rate ....................................................................................................................28

Figure I.13 Major Transmission System Elements in the SPP Region ...................................................30

Figure I.14 DC Tie Transmission Capability ............................................................................................31

Figure II.1 Electricity Sales in the EIS Market by Month for 2009 – 2010 ............................................33

Figure II.2 Electricity Purchases in the EIS Market by Month for 2009 – 2010 ...................................33

Figure II.3 Regional Electricity Price Comparison for 2010 ...................................................................34

Figure II.4 Regional Electricity Price Characteristics for 2010 ..............................................................35

Figure II.5 SPP, MISO, and ERCOT Hourly Average Prices for 2008 – 2010 ......................................35

Figure II.6 Comparison of Average Monthly SPP Prices and Panhandle Natural Gas Prices ............36

Figure II.7 SPP, MISO, ERCOT Hourly Price Ranges for 2010 (90th percentile) ................................37

Figure II.8 Price Duration Curve for 2008 through 2010 ........................................................................38

Figure II.9 Average Annual Price by Market Participant .......................................................................39

Figure II.10 Volatility by Market Participant for 2010 ............................................................................40

Figure II.11 Annual Price Range by Market Participant ........................................................................41

Figure II.12 Average Monthly Price by Market Participant ...................................................................42

Figure II.13 Interval Prices beyond Threshold Levels for 2010 ..............................................................43

Figure II.14 Percent of Re-priced Hours by Month from 2008 – 2010 ...................................................44
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Figure II.15 2010 Price Contour Map ........................................................................................................45

Figure II.16 Principal Congested Flowgates by Area ...............................................................................46

Figure II.17 Key Assumptions in Revenue Adequacy Formulation........................................................48

Figure II.18 Revenue Adequacy Results ....................................................................................................49

Figure II.19 Revenue Adequacy Results for Select Market Participants ...............................................49

Figure II.20 Percent Generation by Fuel Type for 2010 ..........................................................................50

Figure II.21 GWh Generation by Fuel Type for 2010 ..............................................................................51

Figure II.22 Generation at the Margin in 2010 .........................................................................................52

Figure II.23 Wind Capacity and Generation ............................................................................................53

Figure II.24 Dispatchable Range of Available Resources ........................................................................54

Figure II.25 Ramp Availability and Deficiency Intervals ........................................................................55

Figure II.26 Ramp and Average Online Capacity ....................................................................................56

Figure II.27 Generation by Status Type ....................................................................................................57

Figure II.28 Effect of FERC and SPP Offer Caps in 2010 .......................................................................59

Figure II.29 Effect of SPP Offer Caps in 2010 ..........................................................................................60

Figure II.30 Herfindahl-Hirschman Index (Market Participant Capacity) ...........................................61

Figure II.31 Herfindahl-Hirschman Index (Uncommitted Capacity) .....................................................61

Figure II.32 Uncommitted Capacity Market Shares 2010 .......................................................................62

Figure II.33 Components of RNU by Month for 2010 ..............................................................................65

Figure II.34 All-In Price by Month for 2010 .............................................................................................66

Figure II.35 Monthly Net vs. Absolute Energy Imbalance Revenue Neutrality Uplift 2007-2010 .......67

Figure III.1 Transmission Owner Revenue for 2010 ................................................................................69

Figure III.2 Annual SPP Transmission Service Requests ........................................................................70

Figure III.3 Monthly SPP Transmission Service Requests by Status from 2007 – 2010 .......................71

Figure III.4 Monthly Approved and Refused Transmission Service Requests from 2007 – 2010 .......72

Figure III.5 Percent of Five-minute Intervals with at Least One Flowgate Congested ........................74

Figure III.6 Percent congestion by Time Status ........................................................................................75

Figure III.7 Intervals with Breached Flowgates .......................................................................................76

Figure III.8 Intervals with Binding Flowgates ..........................................................................................77

Figure III.9 Top 20 Time Constrained Flowgates.....................................................................................78
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Figure III.10 Top 20 Constrained Flowgates by Shadowprice ................................................................79

Figure III.11 Total Transmission Outage Days for 2004 through 2010 .................................................80

Figure III.12 Days of Transmission Outage by Month for 2004 – 2010 .................................................81

Figure III.13 Days of Transmission Outages by Balancing Authority ...................................................82

Figure III.14 Ratio of Days of Transmission Outage Days to Number of Transmission Facilities ......83

Figure III.15 Generation Outages (MW) by Status ..................................................................................84

Figure III.16 Generation Interconnection Requests by Category (MW) ...............................................85

Figure III.17 Generation Interconnection Requests by Fuel Type (MW) ..............................................86

Figure IV.1 Changes in Congestion Management ....................................................................................98
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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. Southwest Power Pool, Inc. 

(“SPP”) makes no representations or warranties of any kind, express or implied, with respect to the 

accuracy or adequacy of the information contained herein. SPP shall have no liability to recipients of 

this information or third parties for the consequences arising from errors or discrepancies in this 

information, for recipients’ or third parties’ reliance upon such 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) any loss of 

business or other consequential loss or damage whether or not resulting from any of the foregoing. 

 
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SPP 2010 State of the Market Report 9

Executive Summary 

A. Purpose

The Market Monitoring Unit (MMU) is the independent market monitor for the Southwest Power Pool 

(SPP) Regional Transmission Organization (RTO), and it provides an annual report on electricity market 

conditions to the SPP Board of Directors, the Federal Energy Regulatory Commission (FERC), the SPP 

Regional State Committee, and other interested stakeholders. FERC requires State of the Market Reports 

from all RTO and Independent System Operator MMUs; this report fulfills that obligation. 

This report provides an overview of: 

• Supply and demand conditions in the SPP footprint 

• SPP Energy Imbalance Service (EIS) Market results 

• Transmission service markets 

• MMU conclusions and recommendations 

B. Overview of the SPP Footprint

Electricity Supply and Demand 

In 2010 the EIS Market footprint’s peak electric demand was a record 45,373 MW, an increase of 

approximately 14% from 2009. This substantial increase in peak demand was primarily caused by 

weather-driven load requirements and the entry of new Market Participants after the summer peak of 

2009. Excessively hot weather occurred throughout the SPP region during July and August of 2010, 

driving peak demand well above historical levels. 

Total 2010 energy production was approximately 223 million MWh, an increase of approximately 

13% from 2009. Total load during several months set new records for demand. The principal driver 

of this increase was pervasive hot weather in most of the SPP region during the summer months and 

the addition of new Market Participant loads. 

Total year end 2010 generating capacity was 64,787 MW, an increase of 2.8% or 1,774 MW from 

2009; over half of the additional capacity came from coal-fueled generation facilities, followed by 

wind generation facilities. 

SPP has a significant resource margin. The region’s total annual generating capacity compared to 

peak demand results in the SPP resource margin: the amount of extra system capacity available after 

peak load has been served. In 2010, the reserve margin was almost 32%. This healthy resource 

margin can have positive implications for both reliability and for mitigation of the potential exercise 

of market power within SPP. 
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Generation Interconnection 

As of the end of 2010, SPP had 140 active generation interconnection requests representing 

25,892MW of potential generation under study. The vast majority of the queued interconnection 

requests represent wind resources, at 19,902MW. Gas generation was a very distant second with 

2,856MW under study, and coal generation trails at 2,810MW. Generation in the interconnection 

queue does not represent the actual generation under construction. It does however serve as a gauge 

of interest in the construction of new generating facilities in the SPP region. 

Generation and Transmission Outages 

Generation and transmission facilities experience outages when they are unavailable for use by the 

SPP system. Maintenance outages occur when a facility is scheduled to be out of service; these 

outages are typically coordinated with SPP. Forced outages occur when an unforeseen situation 

requires the facility to be removed from service. 

In 2010, generation outages followed the expected trend of increased forced outages in the summer 

peak months and increased maintenance outages during the shoulder months. Transmission outages 

followed a similar pattern; there were substantially fewer transmission outages during summer 

compared to the shoulder months. 

C. EIS Market Results

Market Activity 

In an imbalance market, a Market Participant makes a sale when (a) it generates more than it 

scheduled and/or (b) its actual load is less than it scheduled. Similarly, a Market Participant makes a 

purchase when (a) it generates less than it scheduled and/or (b) its actual load is more than it 

scheduled. 

Total imbalance electric energy in the 2010 SPP EIS Market, measured by both sales and purchases, 

declined by approximately 3%. This decline may appear contradictory to the record system demand 

and load; however, energy imbalance is not necessarily correlated with extreme loading events, but 

is instead correlated with unaccounted for changes in load and resource scheduling. 

Market Prices 

Electricity prices are a result of electricity supply and demand and the ability of the transmission 

system to move electricity from generators to loads. This report includes two separate views of 

prices: price comparisons with neighboring regions and price comparisons among SPP EIS Market 

Participants. 

SPP prices are consistent compared to system prices from the Electric Reliability Council of Texas 

(ERCOT), and the Midwest Independent System Operator (MISO). SPP’s yearly average price of 

$31.36 is slightly lower than MISO’s $31.86, and well below ERCOT’s $35.49. Price equalization 
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SPP 2010 State of the Market Report 11

between these regions is not realistic, but relative prices are similar to each other, indicating the three 

regional markets are yielding comparable results. 

The second views of EIS Market prices assess price differentials between SPP Market Participants. 

While the SPP regional price was $31.36, average Market Participant prices ranged from a low of 

$25.45 to a high of $35.18. These price differences reflect transmission congestion and transfer 

limitations across the SPP footprint. If there was no congestion in the SPP region, the prices at all 

points would be identical. A review of high Market Participant price differentials reveals areas that 

would most benefit from additional transmission capacity. In areas where significant differentials 

exist, additional development would help create parity by encouraging the total transfer of energy, 

yielding efficiency gains. 

Revenue Adequacy (Cost Recovery Determination) 

Revenue adequacy is a metric that calculates whether expected revenue from a new generating 

facility is sufficient to recover the annualized cost of constructing a generator and achieving a 

reasonable rate of return on the investment. This metric considers Locational Imbalance Prices (LIP) 

and determines if the new generator would have been profitable had it been in service. 

In 2010, LIP values did not indicate that it would make purely economic sense to have constructed 

new generating facilities, even in constrained areas where prices tend to be higher than average. In 

the near-term, the large resource margin and abundance of lower-cost gas (which allows for 

continued low prices) precludes the rationale for further generation investment in the SPP system 

based on pure economics. 

Fuel Type 

Understanding the SPP system’s fuel types is vital to understanding the EIS Market’s existing 

generating capacity and pricing structure. Moreover, by analyzing the fuel structure, conclusions 

can be drawn regarding the impact of proposed environmental legislation, as well as reliability 

implications if a particular fuel type was to be removed from service. 

The generation by fuel type metric considers the diversity of fuel types used in the SPP region. In 

2010, coal accounted for 62% of all generation in the SPP EIS Market footprint, natural gas was a 

distant second with 22%, and nuclear facilities were third with slightly less than 10%. Intermittent 

resources, in the form of run-of-river hydro and wind, accounted for slightly more than 5% of total 

generation. 

 

In the SPP EIS Market the marginal resource sets the system price. Analyzing the marginal 

resource’s fuel type provides information about expected system prices. In 2010, coal was on the 

margin approximately 38% of the time. This means that 38% of the time gas units were at 

minimums and coal generation was required to move to meet changes in total system demand. 

Natural gas was on the margin 62% of the time, indicating that coal units were at maximum and that 

gas generation was required to serve changes in system load. Using the above data, system prices 
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SPP 2010 State of the Market Report 12

should reflect marginal costs from coal and natural gas generators in roughly the same proportions as 

indicated by their marginal time. 

The fuel type metrics also provide a review of wind generation in the EIS Market. In 2010 there 

were approximately 4,000 MW of wind capacity, which produced approximately 10,000 GWh of 

energy or 4.8% of the system total. This is an 11% increase from 2009 and a 40% increase from 

2008. Wind development in the region is substantial and is becoming an important issue to monitor. 

Market Participation 

The ways in which a Market Participant participates in the market has significant impact on the 

overall efficiency of the market. The metrics of the Market Participation section provide an 

understanding of the market’s dynamic and interconnected nature. Common metrics that describe 

market participation include analysis of dispatchable range, ramp rates, and status type use. Results 

of this type of analysis may indicate problems with market design, appropriate price signals, 

educational opportunities, or the need for operational improvements. 

Dispatchable Range - The area between minimum and maximum dispatch values in which the 

Market Operating System can move the resource to support changes in supply and demand is known 

as its dispatchable range. If this aggregate area is small, the market will have a more difficult time 

balancing total demand with supply, which could lead to market insufficiencies or ramp shortages. In 

2010, the dispatchable range average was 36.4%, a decrease from 38.5% in 2009 and 40.8% in 2008. 

This noticeable downward trend is a concern. As the market’s dispatchable range contracts, its 

ability to respond to changing conditions diminishes. The MMU encourages all parties to analyze 

this issue and determine if the dispatchable range of Market Participants’ resources can be increased. 

Ramp Rate – The ramp rate is the amount a generator can change its output on a minute-by-minute 

basis. The aggregate of resource ramp rate is the total amount of generation change that can be 

achieved in a given interval. The 2010 average per-minute ramp rate was 276 MW, an increase of 

14% from 2009. This increase is an encouraging result; however there are still occurrences of ramp 

deficiency. 

Status Type Use – Another way to measure the ability of the market to adjust to changes is to 

analyze generators’ resource status types. Resources in “available” status for market dispatch offer 

the most flexibility by allowing dispatch capability and setting the market clearing price. In 2010, 

resources available for market dispatch accounted for 77% of all generation, comparing favorably to 

78% in 2009 and 79% in 2008. Resources in “manual” status accounted for 11% of total generation, 

a slight increase from 10% in 2009 and 2008. Generation from nuclear facilities, while technically 

available, has virtually no dispatch capacity and is treated as a subset of “available” status. Nuclear 

generation in 2010 was 9% of the total, up from 8% in 2009 and 5% in 2008. 
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Market Power Mitigation 

SPP is required by its Tariff provisions to have two offer capping programs. The SPP offer cap 

program screens Market Participants’ price offers based on their respective congestion and locationspecific fuel costs. This offer cap is implemented for impacting and affiliate resources, only when 

the system is congested. The offer cap limits offers from Market Participant resources when 

constrained conditions create prices that would unduly benefit generation from affiliated resources. 

In 2010, only .036% of resource intervals were dispatched near the SPP offer cap. 

 

The FERC cap, an absolute maximum bid cap, serves to limit the maximum bidding allowed into the 

EIS Market. This cap is currently $1,000. In 2010, resources were dispatched near this cap .0046% 

of the time. 

Market Power Monitoring  

The SPP MMU has been expressly charged with monitoring for instances of market power and 

developing various screens and tools that aid in the identification of potential market power abuses. 

A common measure of relative market power is the Herfindahl-Hirschman Index (HHI). The HHI is 

the sum of the squares of market shares for all EIS Market Participants, and shows relative 

concentration within the market. The traditional threshold values of the HHI are: 

• <1000: Low concentration and little possibility of market power abuse 

• Between 1000 and 1800: moderate concentration and medium probability of market power 

• >1800 (traditional markets) >2500(electric markets): High concentration and increased 

probability of market power 

In 2010, the HHI was 909, a slight decrease from 932 in 2009, and a marked decline from 1466 in 

2008. The very low HHI indicates that a Market Participant is unlikely to be successful in exercising 

market power by withholding capacity. 

Revenue Neutrality Uplift 

The SPP EIS Market outcome must yield results that leave SPP revenue neutral. In every interval, 

payments to and from Market Participants must be equal or an adder must be applied to achieve 

neutrality. The adder is called “uplift”, because the amount of the adder must be uplifted to or from 

each Market Participant. Total net uplift in 2010 was -$2.3 million; there was substantial monthly 

variability throughout the year ranging from $2.3 million to -$1.9 million. 

Because revenue neutrality must be maintained and uplift applied to all Market Participants, it 

summarily affects the total cost of energy. Adding the uplift total to the average system energy cost 

demonstrates the net effect of system uplift. In 2010, the average MWh adder was -$.04, with 

divergence that ranged from $.74 to -$.54 per MWh on a monthly average basis. This represents a 

very small percentage of the average energy costs and does not present an issue at this time. 
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SPP 2010 State of the Market Report 14

D. Energy Delivery

Transmission systems are pathways that link generators to load centers. There is substantial 

variability among these pathways both within an individual region and across regions. This 

variability includes voltage type, line length, configuration, and operating characteristics, among 

many others. 

Transmission Owner Revenue 

Under its Open Access Transmission Tariff, SPP grants transmission service over transmission 

systems on behalf of the various member companies who own transmission assets. Members are 

entitled to revenues from this granted transmission service. In 2010, total transmission owner 

revenue was approximately $628 million, an increase of approximately 30% from $486 million in 

2009. 

Transmission Service Requests 

Entities in the SPP footprint that want to use the transmission system must request service from SPP. 

SPP will approve as many requests as possible while maintaining system reliability and feasibility. 

There were 115,000 requests for transmission service in 2010, a slight increase from 2009 and a 

substantial drop from 2007 and 2008. From the MMU’s perspective, the total number of requests is 

less significant than the number of requests that are approved by SPP. The number of approved 

requests fell steadily throughout 2010, which is a concern. This decline may be the result of changes 

in loading, congestion patterns, or better transmission utilization. SPP needs to analyze the 

conditions that caused this trend. 

Transmission Congestion 

Transmission congestion causes prices to diverge as less economical units are used to balance supply 

and demand while maintaining reliability. The most common way to maintain system reliability is 

by using monitored elements called “flowgates”, which represent flow points. Operators can achieve 

system control and stability by monitoring and controlling flow over flowgates. 

Flowgate congestion - the number of intervals in which a flowgate was at or exceeded its limit - was 

69% in 2010, down slightly from 71% in 2009. This level of congestion is not necessarily a concern, 

as congestion in the form of binding flowgates can indicate that the transmission system is being 

fully utilized. However, breached flowgates or those that have exceeded their limit are problematic. 

In 2010, approximately 5% of all dispatch intervals included a breached flowgate. Breached 

flowgates lead to significant price differentials across the region and can adversely impact individual 

market participants. High levels of price volatility from breached flowgates can discourage 

participation in the market and thereby reduce benefits of the market. 

Transmission Outages 

Transmission outages can be forced, in which an unforeseen event causes a facility to become 

unavailable, or planned, in which a transmission owner schedules the outage for maintenance or 
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SPP 2010 State of the Market Report 15

some other planned reason. Total transmission outages have been increasing steadily for the past 

several years, including 2010. There were more than 26000 transmission outage days in 2010. A 

transmission outage day is equal to one outage day per element out of service (three transmission 

elements out for four days would count as 12 transmission outage days). The total number of 

outages, while increased from 2009, is not problematic at this time. 

Transmission Investment 

The 2010 SPP Transmission Expansion Plan (STEP) summarized 2010 activities that impact future 

development of the SPP transmission grid. The 2010 STEP determines needed transmission 

investments for the ten-year period from January 1, 2011 through December 31, 2021. Transmission 

expansion projects total more than $5.1 billion dollars. Projects include: 3,295 miles of new 

transmission lines, 947 miles of reconductored transmission lines, 753Mvar of new capacitors, and 

over 100 new or upgraded transformers. The vast majority of the total cost of development stems 

from new transmission lines, at almost $3.5 billion of the total. New transformers are a distant 

second with just under $500 million in total cost. 

The final section of this report contains the conclusions and discussion of the performance of the 

SPP EIS Market in 2010. Overall, the market continues to be competitive and participation is at very 

high levels. The discussion focuses on issues of competitiveness, localized congestion, seams issues, 

and the Integrated Marketplace design. 

 
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SPP 2010 State of the Market Report 16

I. Overview of SPP Footprint 

To ensure a consistent methodology and enhance future reporting, and unless otherwise expressly 

stated, metrics in this report have been formulated using only the Market Participant footprint. This 

enhances the report’s consistency and provides a firm foundation for analysis. Because this is a 

substantial change from previous years, a direct comparison between numbers published in this 

report and previous reports may not be possible. Where applicable, the MMU has provided historical 

data for the market footprint to ensure that analysis across time may be performed. 

A. Brief Overview of SPP

SPP is a Regional Transmission Organization (RTO) mandated by the Federal Energy Regulatory 

Commission (FERC) to ensure reliable power supplies, adequate transmission infrastructure, and 

competitive wholesale electricity prices. SPP was granted RTO status by FERC in 2004. SPP is one 

of nine Independent System Operators/RTOs and one of eight NERC Regional Entities. SPP 

provides many services to its members including reliability coordination, tariff administration, 

regional scheduling, transmission expansion planning, training, and market operations. Market 

operations and 2010 Energy Imbalance Service Market (EIS) results are discussed in this report. 

In 2007 SPP launched its real-time EIS Market, comprised of participants that agreed to operate 

under the SPP Tariff, and Market Protocols. The market does not include all SPP members, only 

those that have agreed to the above terms and provisions. The Market Participant’s respective areas 

collectively form the EIS Market footprint. Unless otherwise stated, the EIS Market footprint is used 

for the metrics in this report. 

In addition to the EIS Market, SPP is developing new markets. The major components of these new 

markets include: (a) a Day-Ahead Market with Transmission Congestion Rights, (b) a Reliability 

Unit Commitment process, (c) a Real-Time Balancing Market, similar to today’s EIS Market, and 

(d) a price-based Operating Reserves procurement. These markets are tentatively scheduled for 

launch in 2014. 
Southwest Power Pool, Inc.                    

SPP 2010 State of the Market Report 17

SPP’s Location 

SPP is located in the southwest portion of the Eastern Interconnection. It is bordered by the Midwest 

Reliability Organization (MRO) and the SERC Reliability Corporation (SERC) in the Eastern 

Interconnection. SPP also shares borders with the Western Electricity Coordinating Council 

(WECC) and the Texas Regional Entity (TRE). Figure I.1 shows the four NERC Interconnections 

and the eight Regional Entities in North America. 

Figure I.1 NERC Interconnections 

Source: NERC.com 
Southwest Power Pool, Inc.                    

SPP 2010 State of the Market Report 18

SPP Membership 

At the end of 2010, SPP had 61 members that serve load, provide generation, and/or own or use 

transmission facilities. SPP members include cooperatives, municipals, state agencies, independent 

transmission companies, investor-owned utilities, independent power producers, and power 

marketers. For a list of all SPP members, visit SPP.org>About>Members. 

Figure I.2 Members as of December 31, 2010 

SPP Members Number of Members

Cooperatives 12

Independent Power Producers / Wholesale Generators 7

Independent Transmission Companies 5

Investor‐Owned Utilities 14

Marketers 10

Municipals 9

State Agencies 4

Total Members 61
Southwest Power Pool, Inc.                    

SPP 2010 State of the Market Report 19

SPP Balancing Authorities 

The SPP market footprint is comprised of 15 Balancing Authorities, which are operated by investorowned utilities, cooperatives, municipals, and state agencies. A Balancing Authority is responsible 

for managing the minute-to-minute supply and demand for electricity within a specific territory. A 

rough approximation of the locations of these Balancing Authorities is shown in Figure I.3. 

Figure I.3 Map of SPP Balancing Authorities 
Southwest Power Pool, Inc.                    

SPP 2010 State of the Market Report 20

B. Electricity Demand in the SPP Region

The SPP EIS Market is comprised of Market Participants who have individual load and resource 

profiles, but are all commonly served by SPP. A standard way to compare load changes across time 

is to review peak system demand statistics by year. Figure I.4 depicts monthly peak electric energy 

demand for the SPP market footprint for the past four years. It is important to consider that the 

market footprint changes over time as participants are added or removed. The peak MW value is 

coincident, representing total peak dispatch that occurred during a particular market interval. The 

peak experienced during a particular year or season may represent an outlier event with little 

correlation either to average or seasonal load patterns. 

 

System Peak Demand 

As can be seen in the Figure 1.4, the peak load experienced during 2010 was 45,373 MW, an 

increase of 14.5 percent from 2009. The SPP region experienced extraordinarily hot conditions 

during July and August 2010, which resulted in greatly increased demand. A month-by-month 

comparison shows substantial growth from 2009 to 2010 for most months, and may be an indicator 

of positive economic growth in the SPP region. It is important to note that there was a significant 

increase in mid 2009 because of new entrants to the SPP market. A significant portion of the 

increase from 2009 to 2010 for the months of January through March can be attributed to these new 

participants. 

Figure I.4 Monthly Peak Electric Energy Demand for the SPP Market Region (MW) 

Month 2007 2008 2009 2010

JAN N/A 25,651 25,785 35,079

FEB N/A 24,484 24,424 31,789

MAR N/A 23,067 23,039 28,456

APR 21,835 21,711 25,675 25,725

MAY 26,352 28,438 28,685 34,754

JUN 29,503 31,358 39,502 41,828

JUL 32,127 34,467 39,622 42,161

AUG 35,777 36,538 38,790 45,373

SEP 30,419 28,149 32,136 35,760

OCT 28,012 22,171 25,816 28,574

NOV 21,663 22,542 26,805 28,628

DEC 23,750 27,066 32,594 31,072
Southwest Power Pool, Inc.                    

SPP 2010 State of the Market Report 21

Market Participant Peak and Total Demand 

Figure I.5 depicts 2010 total load, the percent of load attributable to a Market Participant, and 

Market Participants’ peak loads. The largest five participants account for over half of the total 

system load. This is not unexpected, as SPP is primarily comprised of legacy vertically integrated 

utilities, which tend to be quite large. Many Market Participants experienced significant, and in some 

cases record peaks, within their respective territories in 2010. The extraordinarily hot weather in 

much of the SPP region was the significant driver of peak electricity demand. 

Figure I.5 Market Participant Demand and Electric Energy Usage in 2010 

Market

Participant

2010 Total

Load (MWh)

Percent of

System Total

Peak

(MW)

AECC 3,820,936 1.71% 856

AEPM 44,122,145 19.78% 9,199

BEPM 769,728 0.35% 280

EDEP 5,588,648 2.51% 1,195

GMOC 9,081,488 4.07% 1,951

GRDX 4,621,155 2.07% 917

GSEC 3,648,426 1.64% 793

INDN 1,171,450 0.53% 305

KBPU 2,583,377 1.16% 500

KCPS 16,944,780 7.60% 3,726

KPP 2,029,767 0.91% 423

LESM 3,503,609 1.57% 766

MEAN 617,948 0.28% 144

MIDW 1,530,978 0.69% 332

OGE 29,626,195 13.28% 6,252

OMPA 2,286,555 1.03% 553

OPPM 12,219,284 5.48% 2,575

SECI 5,440,985 2.44% 1,052

SPSM 26,951,839 12.08% 5,088

TEAN 13,530,343 6.07% 2,670

TNSK 28,537 0.01% 10

WFES 7,631,939 3.42% 1,489

WRGS 25,280,259 11.33% 5,534

System Total 223,030,369 100.00%
Southwest Power Pool, Inc.                    

SPP 2010 State of the Market Report 22

Total SPP system load has increased steadily over the past several years. In 2010 total system load 

was higher in each month compared to 2009, and 2009 levels were higher than 2008 during most 

months. Weather was the principal driver for most of the load increases. Periods of extremely hot 

weather in 2009 and 2010 summers, and significant cold spells during parts of 2010, added to total 

demand during the affected months. The exception is for the months of January through March. The 

year over year increase was primarily driven by the addition of new market participants in Nebraska. 

Population growth in the SPP region has been substantial, roughly a 9% increase over the past 

decade in the component states. These factors have served to increase the total load in 2010 by over 

13% from 2009. 

Figure I.6 Total System Load (MWh) 

 

Month 2008 2009 2010

JAN 15,113,486 14,848,933 19,359,032

FEB 13,664,629 12,247,958 17,188,945

MAR 13,440,300 13,107,718 16,618,388

APR 12,819,711 14,452,450 15,124,557

MAY 14,061,726 15,507,512 17,163,476

JUN 16,540,860 18,931,329 21,261,878

JUL 18,638,178 20,643,673 22,994,452

AUG 17,759,991 20,293,356 24,403,925

SEP 14,113,763 16,634,983 18,583,166

OCT 13,020,357 15,521,744 15,972,880

NOV 12,828,939 15,453,570 15,893,856

DEC 14,844,294 19,163,485 18,465,814
Southwest Power Pool, Inc.                    

SPP 2010 State of the Market Report 23

System Demand Profile 

Figure I.7 depicts total minimum and maximum hourly demand for 2008-2010. There is a significant 

upward trend in both minimum and maximum hourly peak values, and a substantial and relatively 

consistent spread between hourly values during 2010 summer months. This is further evidence that 

the prolonged elevated temperatures in much of the SPP region caused dramatic changes in normal 

system demand patterns. 

This chart depicts the total sum of MWs that EIS Market resources must move to meet changes in 

load. The maximum daily spread between minimum and maximum values is over 18,000 MW; the 

EIS Market had to adjust the output of market resources by 18,000 MW throughout the day to 

balance supply and demand. If the change in demand across time is fairly consistent, the strain of 

maintaining the balance between available generation and demand is lessened and the likelihood of a 

ramp constraint condition is minimized. However, if changes in demand or loading are sudden, it 

may be more than the system is capable of handling in the short-term, which would result in a ramp 

constraint condition. Ramp constrained conditions indicate where market inefficiencies are likely to 

occur and highlight areas where enhancing market parameters would be most useful. 

Figure I.7 Daily Minimum and Maximum Electric Energy Demand 2008 – 2010 

0

5000

10000

15000

20000

25000

30000

35000

40000

45000

50000

1‐Jan‐08

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1‐Jun‐10

1‐Jul‐10

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1‐Oct‐10

1‐Nov‐10

1‐Dec‐10

MW

Daily Minimum Daily Maximum Spread
Southwest Power Pool, Inc.                    

SPP 2010 State of the Market Report 24

Load Duration Curve 

Figure I.8 depicts load duration curves for 2008-2010. A load duration curve is a modified display of 

load against time. It is a reordered version of the traditional load curve, as shown above in Figure I.7, 

in which hourly load values are sorted by magnitude instead of chronologically. A load duration 

curve shows the relative magnitude and frequency of load throughout the year. 

In 2010 the total system load peaked at approximately 45,000 MW, with a minimum of 

approximately 16,000 MW. Reference lines and percentages indicate the relative persistence of 2010 

load levels. In 2010, 2% of all loads were greater than a reference level of 40,000 MW (the peak in 

2009). Load was between 25,000 MW and 30,000 MW 26% of the time. Comparing annual load 

duration curves shows better differentiation between cases of extreme loading events and more 

general increases in system demand. If only the extremes are higher than the previous year, shortterm loading events are likely the reason. However, if the entire load curve is higher than the 

previous year, it indicates that total system demand has increased, which is the case as shown below. 

There is a distinct bend in 2010’s upper load values, which is likely due to extreme loading caused 

by weather in July and August. 

Figure I.8 Electric Load Duration Curve 2008 -2010 

0

5000

10000

15000

20000

25000

30000

35000

40000

45000

50000

1 1001 2001 3001 4001 5001 6001 7001 8001

Load (MW)

2008

2009

2010

2% of hours

5% of hours

10% of hours

26% of hours

45% of hours

14% of hours
Southwest Power Pool, Inc.                    

SPP 2010 State of the Market Report 25

Summary and Conclusions 

Total load in the SPP region has increased steadily over the past several years. Continued load 

growth is expected as population increases and the demand for energy subsequently increases. 

Economic recovery should increase total energy demand from the commercial and industrial sectors. 

Load growth patterns are an important consideration in the RTO’s modeling efforts, and the MMU 

encourages SPP to fully quantify the expected growth pattern throughout the SPP region. 
Southwest Power Pool, Inc.                    

SPP 2010 State of the Market Report 26

C. Generation – The Supply of Electricity

Capacity in the SPP Market Region 

Figure I.9 depicts the EIS Market’s Balancing Authorities and corresponding sum of their installed 

generating capacity as of December 31, 2010. Total generating capacity in the SPP EIS Market 

region was 65,524 MW, a 4% increase over 2009’s total generation capacity. The increase is largely 

attributable to the construction of new generating facilities in the region. 

Figure I.9 Current Installed Generation Capacity by Balancing Authority 

Balancing

Authority

Capacity

(MW)

CSWS 16864

EDE 2221

GRDA 1510

INDN 354

KACY 649

KCPL 5103

LES 534

MPS 2874

NPPD 3383

OKGE 9440

OPPD 3771

SECI 1113

SPS 7444

WFEC 1817

WR 7710

Total 64787
Southwest Power Pool, Inc.                    

SPP 2010 State of the Market Report 27

Resource Margin 

As depicted in Figure 1.10, SPP has a significant resource margin. The region’s total annual 

generating capacity compared to peak demand results in the SPP resource margin: the amount of 

extra system capacity available after peak load has been served. In 2010, the reserve margin was 

almost 32%. This healthy resource margin can have positive implications for both reliability and for 

mitigation of the potential exercise of market power within SPP. 

Figure 1.10 Resource Margin by Year 

Capacity Additions in 2010 

Figure I.11 shows the total amount of installed capacity by fuel type that was added in 2010. There 

was a substantial increase in coal generation and a resurgence of wind generation additions in the 

latter half of 2010. 

Figure I.11 Capacity Additions by Fuel Type 

Fuel Type Capacity Addition

Coal 915

Gas 210

Oil 20

Other 6

Wind 651

Total 1802

Year

Capacity

(MW)

Peak

Load

Resource

Margin

2007 52,465 35,777 31.81%

2008 55,473 36,538 34.13%

2009 66,744 39,622 40.64%

2010 64,956 45,373 30.15%
Southwest Power Pool, Inc.                    

SPP 2010 State of the Market Report 28

Implied Heat Rate 

A common way to determine the relative impact of a region’s scarcity pricing is to study the Implied 

Heat Rate. The implied heat rate is the ratio of the natural gas price and the system’s electricity 

price. If the price of natural gas was $4.50MMBtu, and the LIP was $40.00 MWh, the implied heat 

rate would be (40.00/4.5) = 8888 MMBtu/MWh. This implied heat rate shows the relative efficiency 

required of a generator to convert gas to electricity and break even, given system prices. 

Figure I.12 shows the Implied Heat Rate for the years 2007-2010. The implied heat rate shows 

significant spikes during some months which are largely coincident with peak loading events or 

significant transmission congestion issues. When the implied heat rate increases, the relative value of 

additional efficient generation also increases. Generation that otherwise would not have been needed 

was required to meet system demand, and prices increased accordingly. 

Figure I.12 Implied Heat Rate 

5

6

7

8

9

10

11

12

ImpliedHeat Rate (MMBtu/MWh)
Southwest Power Pool, Inc.                    

SPP 2010 State of the Market Report 29

Summary and Conclusions 

There is little cause to be concerned about generation supply in the SPP region. New capacity is 

being added, additional wind resources are being developed, and a large resource margin is in place. 

These factors indicate there is sufficient generation capacity in the region for the foreseeable future. 

This does not mean capacity additions at select locations are not needed; it implies that capacity at 

the system level is sufficient. 

Even with the SPP region’s large capacity margin, rapid load growth should be carefully monitored 

to ensure generation is deliverable to the load centers. By coordinating and managing interfaces with 

neighboring regions, excess capacity may be utilized in the form of power sales to external entities. 

The continued development of wind resources may have unanticipated consequences if the power 

flows become overly unpredictable. It is essential that SPP incorporate and manage these resources 

into the overall supply stack. The MMU encourages SPP to better understand the total volatility of 

these types of generators and determine what steps, if any, are necessary to ensure their successful 

integration into the current resource mix. Furthermore, a determination on the construction cost 

allocation of transmission infrastructure necessary to support wind generation will be critical to the 

continued development of renewable resources. 
Southwest Power Pool, Inc.                    

SPP 2010 State of the Market Report 30

D. Transmission – The Bridge between Supply and Demand

Transmission System Characteristics 

Six primary transmission voltages are used in the SPP region: 345 kV, 230 kV, 161 kV, 138 kV, 115 

kV, and 69 kV. Balancing Authorities in the SPP region use differing voltage levels as the backbone 

of their respective systems. 345 kV is the predominant backbone voltage for much of SPP’s eastern 

portion. 230 kV is the backbone voltage in much of the western part of the region, most notably in 

the Southwestern Public Service area. Regardless of the backbone voltage, most of the SPP region 

uses the 69 kV system as the cutoff for step-down between their transmission and distribution 

systems. Figure I.13 shows the major transmission elements in the SPP region. 

Figure I.13 Major Transmission System Elements in the SPP Region 

Depicted 230 kV+ in-service as of April 1, 2010 
Southwest Power Pool, Inc.                    

SPP 2010 State of the Market Report 31

Inter-grid Connection Points 

In addition to the alternating current grid referenced above, there are seven direct current (DC) ties 

with other interconnections. These DC ties serve as interconnection points to other grids by 

converting power through AC-DC-AC interfaces. A unique characteristic of this type of interface is 

its controllability and stability. Energy transfers are known, easily identifiable, and very tightly 

controlled. A list of the seven DC ties is provided in Figure I.14. 

Two of the DC ties connect the SPP region with the Electric Reliability Council of Texas (ERCOT) 

area: ERCOT East and ERCOT North. Five DC ties connect the SPP region to the Western 

Electricity Coordinating Council area: Lamar, Eddy County, Blackwater, Sidney, and Stegall. Tie 

capacity is depicted in Figure I.14. 

Figure I.14 DC Tie Transmission Capability 

Summary and Conclusions 

The SPP region’s transmission system is largely based on legacy systems developed from 

independent vertically integrated utilities. While these systems may be functionally sufficient for 

their respective areas, they may not be sufficient for macro transfers across the region. SPP has been 

working with and coordinating transmission development throughout the region to increase the 

system’s overall reliability, efficiency, and effectiveness. 

DC Tie Name Transmission Capacity (MW)

ERCOT East 600

ERCOT North 210

Lamar 210

Eddy County 200

Blackwater 200

Sidney 200

Stegall 200
Southwest Power Pool, Inc.                    

SPP 2010 State of the Market Report 32

II. EIS Market Activity 

A. Brief Overview of the EIS Market

The SPP EIS Market began operation on February 1, 2007, and settles real-time imbalances between 

generation and load. The EIS Market is comprised of participants that have agreed to operate under 

the SPP Tariff, Market Protocols, and other governing documents. The SPP Market does not include 

all SPP members, only those that have agreed to the above terms and provisions. There are 15 

Balancing Authorities and 32 Market Participants in the Market footprint. A list of all SPP Market 

Participants is found at SPP.org>About>Fast Facts>Footprints. Unless otherwise stated, the SPP EIS 

Market footprint is the reference area for this report. 

B. Market Activity

EIS Sales and Purchases 

A sale in the EIS Market is made when either a resource generates more than was scheduled, or a 

load consumes less than was scheduled. A purchase is made when a resource generates less than was 

scheduled or a load consumes more than what was scheduled. Figure II.1 and Figure II.2 show the 

total volume of EIS sales and purchases that occurred in the SPP region in 2009 and 2010. 

Figure II.1 and Figure II.2 depict that 20.13 million MWh were sold and 20.01 million MWh were 

purchased in the EIS Market in 2010, compared to 20.82 million MWh sold and 20.75 million MWh 

purchased in 2009. The difference between 2010 and 2009 purchases and sales totals is minor; there 

was a 3.30%, decrease in total MWh sales and a 3.56% decrease in total MWh purchases. 

During 2010, participants received approximately $641 million for sales into the EIS market and 

paid approximately $640 million for purchases. From 2009, sales increased 10.72% and purchases 

increased 13.39%. An important aspect of pricing information is that the total magnitude of dollars 

for purchases and sales is driven by gas costs in the SPP region. As the price of gas changes, the total 

energy cost changes, as does the EIS portion of total energy cost. Because of this relationship, a 

large increase in dollars received by Market Participants may not reflect any actual increase in 

overall market activity, but instead may reflect a change in the marginal cost of fuel in the SPP area. 
Southwest Power Pool, Inc.                    

SPP 2010 State of the Market Report 33

Figure II.1 Electricity Sales in the EIS Market by Month for 2009 – 2010 

Figure II.2 Electricity Purchases in the EIS Market by Month for 2009 – 2010 

MWh Sold by

Market

Participants

Dollars

Received by

Market

Participants

MWh Sold by

Market

Participants

Dollars

Received by

Market

Participants

Jan 1,185,553 39,734,012 1,708,319 74,295,720

Feb 1,072,096 26,150,287 1,344,104 56,036,204

Mar 1,490,880 41,951,785 1,551,892 46,948,088

Apr 2,049,867 45,967,394 1,603,909 46,397,389

May 2,296,007 57,245,772 1,709,050 48,237,522

Jun 2,581,722 71,403,535 1,828,020 60,049,992

Jul 2,163,603 61,762,686 1,876,771 64,859,041

Aug 1,750,833 46,132,848 1,897,340 68,007,883

Sep 1,543,249 36,628,991 1,729,000 48,393,089

Oct 1,437,650 43,501,497 1,553,583 39,804,530

Nov 1,518,093 42,598,852 1,566,901 38,051,625

Dec 1,731,930 66,124,337 1,766,165 50,210,505

Total 20,821,483 579,201,996 20,135,053 641,291,588

Month

2009 2010

MWh Purchased

by Market

Participants

Dollars

Received by

Market

Participants

MWh

Purchased by

Market

Participants

Dollars

Received by

Market

Participants

Jan 1,188,142 38,313,457 1,719,066 75,461,654

Feb 1,057,879 25,522,298 1,347,039 54,636,073

Mar 1,493,862 38,377,768 1,564,188 46,359,198

Apr 2,041,624 45,779,130 1,543,511 43,779,554

May 2,275,774 55,209,633 1,642,857 46,673,314

Jun 2,600,313 69,587,458 1,821,442 60,799,763

Jul 2,185,067 60,623,338 1,875,582 65,388,967

Aug 1,755,053 45,372,726 1,899,574 68,022,062

Sep 1,523,855 35,578,335 1,726,110 49,078,824

Oct 1,370,937 40,740,204 1,526,262 39,672,875

Nov 1,511,620 42,844,045 1,577,607 38,804,414

Dec 1,750,441 67,047,724 1,771,997 52,013,519

Total 20,754,565 564,996,115 20,015,236 640,690,216

Month

2009 2010
Southwest Power Pool, Inc.                    

SPP 2010 State of the Market Report 34

C. Market Prices

Regional Price Comparison 

A useful measure of basic market competitiveness is the comparison of prices between SPP and its 

neighboring regions. If prices in neighboring regions are generally in line with prices in the SPP 

region, then basic market operations are yielding similar results. It is not realistic to expect prices to 

be identical across the regions, as market structures vary and resource fuel mixes are markedly 

different. For this review, SPP prices are compared to prices in the Midwest Independent 

Transmission System Operator (MISO) and the Electric Reliability Council of Texas (ERCOT), the 

two electric wholesale markets adjacent to SPP. 

 

Figure II.3 shows 2010 system average prices for the SPP, ERCOT and MISO regions. Prices in the 

SPP region are slightly less than prices in MISO, and substantially less than those in ERCOT. The 

most probable explanation for the price disparity is differing regional fuel mixes. SPP and MISO 

have similar fuel mixes, although MISO has somewhat more coal than SPP, on a percentage basis. 

ERCOT has substantially more gas generation as a percent of capacity than either SPP or MISO. Gas 

generation is typically more expensive to operate than either coal or nuclear generators; 

consequently, system prices tend to be higher in regions with high gas generator concentration. 

Figure II.3 Regional Electricity Price Comparison for 2010 

Another useful means of comparing prices across regions is to review overall price stability in the 

regions. The Volatility column in Figure II.3 represents the average volatility. The volatility is 

calculated by dividing the standard deviation of hourly regional prices by the mean of the hourly 

regional prices, which yields the coefficient of variation. This value represents the relative 

movement of prices across time. If volatility is high, prices tend to be concentrated away from the 

system average, or toward the tails of the price distribution curve. If volatility is low, prices tend to 

be dispersed away from the system average, or near the mean of the price distribution curve. 

 

Figure II.4 shows 2008-2010 average prices for SPP, MISO, and ERCOT. Average prices for all 

three regions were slightly higher in 2010 than in 2009. Average prices in the SPP region increased 

approximately 23% from 2009 to 2010, which is largely attributable to increased natural gas prices 

throughout the region. Panhandle hub gas prices increased 25.73% from 2009 to 2010. SPP chiefly 

uses the Panhandle gas hub as a reference node for changes in gas prices. Other regions use different 

gas hubs, but gas prices are largely consistent across these hubs (or at least the basis difference is 

known between the hubs). The overall trend in gas prices is consistent across these regions. 

Region Average Price Maximum Price Minimum Price Volatility

SPP $31.36 $395.88 ‐$124.97 50%

MISO $31.88 $343.36 ‐$98.15 59%

ERCOT $35.49 $1,011.86 ‐$25.54 105%
Southwest Power Pool, Inc.                    

SPP 2010 State of the Market Report 35

Average On-Peak and Off-Peak prices followed the general trend of average prices, trending higher 

than the previous year. An interesting measure of regional differences is the magnitude of difference 

between Off-Peak prices for the regions. This difference reflects the composition of the regional 

resource fleets. Coal generation capacity comprises a large percentage of the SPP and MISO 

resource fleets and typically has a lower marginal cost than gas generation. When loading is low 

during off-peak times, coal generators are likely the marginal resource, which yields lower system 

prices. 

Figure II.4 Regional Electricity Price Characteristics for 2010 

Figure II.5 depicts 2008- 2010 prices in the SPP, MISO, and ERCOT regions. SPP prices tend to be 

between MISO and ERCOT prices, largely due to different regional resource fleets. The lower offpeak prices for MISO and SPP are attributable to the high percentage of coal units which are more 

likely to set prices in the off-peak period. 

Figure II.5 SPP, MISO, and ERCOT Hourly Average Prices for 2008 – 2010 

Region 2008 2009 2010 2008 2009 2010 2008 2009 2010

SPP $53.16 $27.44 $31.36 $65.01 $31.93 $37.19 $42.57 $23.39 $26.29

MISO $48.33 $27.12 $31.88 $62.31 $33.65 $39.63 $35.80 $21.34 $25.13

ERCOT $64.91 $30.05 $35.49 $79.34 $34.54 $40.21 $55.01 $25.55 $31.40

Average Price Average On‐Peak Price Average Off‐Peak Price

$0

$20

$40

$60

$80

$100

$120

Jan‐08

Feb‐08

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SPP MISO ERCOT
Southwest Power Pool, Inc.                    

SPP 2010 State of the Market Report 36

SPP and Gas Price Comparison 

Figure II.6 compares the average Panhandle hub gas price and the SPP monthly average price for 

2008-2010. Gas prices are very closely associated with average system prices in the SPP region. 

This is logical, because the marginal resources that set overall prices are most often gas units. There 

was a general increase in gas prices, approximately 25% from 2009 to 2010. However, even with 

this increase, average gas prices are well below what was experienced in 2008. 

There is some indication that gas prices are likely to remain near their current levels for some time. 

Several reasons for this are discussed in greater detail later on in this report. If gas prices remain 

stable in the near future, overall system prices in the SPP region will likely also remain quite stable. 

Figure II.6 Comparison of Average Monthly SPP Prices and Panhandle Natural Gas Prices 

0

2

4

6

8

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12

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Jun‐08

Jul‐08

Aug‐08

Sep‐08

Oct‐08

Nov‐08

Dec‐08

Jan‐09

Feb‐09

Mar‐09

Apr‐09

May‐09

Jun‐09

Jul‐09

Aug‐09

Sep‐09

Oct‐09

Nov‐09

Dec‐09

Jan‐10

Feb‐10

Mar‐10

Apr‐10

May‐10

Jun‐10

Jul‐10

Aug‐10

Sep‐10

Oct‐10

Nov‐10

Dec‐10

Gas Prices ($ / MMBtu)

Energy Prices ($ / MWh)

SPP Average On‐peak Panhandle Gas Prices
Southwest Power Pool, Inc.                    

SPP 2010 State of the Market Report 37

Average Hourly Prices 

Figure II.7 shows the hourly price ranges of SPP, MISO, and ERCOT for those prices that fall within 

two standard deviations of the mean. Prices that fall outside of two standard deviations are excluded, 

both on the high and low sides. This was done to better illustrate the normal prices that occur in the 

listed regions. Had those prices outside of two standard deviations been included, the ranges in the 

table would be much greater and indicate that price extremes are more significant than their actual 

occurrence would signify. 

Average hourly prices are largely equivalent across the regions. ERCOT prices are the most volatile, 

as shown by the greatest maximum and minimum prices. SPP prices are the most moderate, with the 

lowest maximum and least negative minimum price. A consistent theme in this pricing data for all 

participants is the weight of prices above the mean. This is a logical result of market operations, as 

congestion costs and other pricing factors should naturally result in price extremes greater than the 

mean. Pricing extremes do occur below the mean, although with less frequency. 

Figure II.7 SPP, MISO, ERCOT Hourly Price Ranges for 2010 (90th percentile) 

‐40

‐20

0

20

40

60

80

100

120

140

ERCOT MISO SPP

$ / MWh

Min Max Average
Southwest Power Pool, Inc.                    

SPP 2010 State of the Market Report 38

Price Duration Curve 

A final look at system prices can be seen in Figure II.8, which depicts a price duration curve similar 

to the load duration curve in Figure I.7, except that system hourly prices are used. Prices are 

substantially lower than in 2008 and slightly higher than 2009. This chart shows the incidence of 

price extremes in relation to total pricing. This can be seen in the tails of the chart, where prices are 

at extreme levels. However, relatively few hours are priced at these extreme levels. 

Figure II.8 Price Duration Curve for 2008 through 2010 

‐200

‐100

0

100

200

300

400

500

600

1 501 1001 1501 2001 2501 3001 3501 4001 4501 5001 5501 6001 6501 7001 7501 8001 8501

2008 2009 2010
Southwest Power Pool, Inc.                    

SPP 2010 State of the Market Report 39

Market Participant Price Comparisons 

While pricing comparisons between SPP and its neighboring regions show the relative robustness of 

the regional markets, they do not assess individual participants within the region. To better 

understand the intricacies of the SPP region, it is necessary to establish metrics that analyze SPP’s 

individual Market Participants. The remaining metrics in this section provide an analytic backbone 

for the review of the SPP EIS Market and its participants. 

Figure II.9 shows annual 2008-2010 average prices for SPP’s EIS Market Participants. 2010 prices 

are above those from 2009 but are substantially below 2008 levels. In 2010, the Golden Spread 

Electric Cooperative (GSEC) area experienced the highest average prices of $35.18, while the 

Lincoln Electric System (LES) area experienced the lowest average prices of $25.45. Prices for these 

two participants represent the SPP region’s extremes, as they are significantly different than the 

$31.33 mean system price. The principal driver of the relative price extremes is congestion costs 

applied to Market Participants’ respective areas. 

Figure II.9 Average Annual Price by Market Participant 

0

10

20

30

40

50

60

70

AECC AEPM BEPM EDEP GMOC GRDX GSEC INDN KBPU KCPS KEPC KPP LESM MEAN MIDW OGE OMPA OPPM SECI SPSM TEAN WFES WRGS

Average Price ($/MWh)

Balancing Authority

2008 2009 2010

SPP System Averages
Southwest Power Pool, Inc.                    

SPP 2010 State of the Market Report 40

Price Volatility 

Comparing average prices across Market Participants provides a rough comparison of price stability. 

Another useful perspective is provided by reviewing price volatility. The volatility experienced by 

Market Participants indicates the relative stability of prices in their regions. Figure II.10 shows 

Market Participants’ volatility using hourly prices. 

Total participant volatility, as calculated with hourly price data, is substantially higher than the 

system’s 53% volatility average. In some cases, Market Participant volatility is more than double the 

system average. This is not necessarily an indicator of a major market problem; however, it indicates 

areas which are impacted the most by congestion and extreme pricing events. High levels of 

volatility present several long run problems, they indicate areas in which price stability is least likely 

to occur, and they may discourage more open participation in the SPP EIS Market. 

Figure II.10 Volatility by Market Participant for 2010 

Market Participant AECC AEPM BEPM EDEP GMOC GRDX GSEC INDN

Volatility 64% 55% 102% 60% 67% 51% 86% 62%

Market Participant KBPU KCPS KPP LESM MEAN MIDW OGE OMPA

Volatility 66% 63% 58% 113% 105% 69% 50% 50%

Market Participant OPPM SECI SPSM TEAN WFES WRGS SPP

Volatility 111% 73% 90% 106% 51% 60% 53%
Southwest Power Pool, Inc.                    

SPP 2010 State of the Market Report 41

Price Spread 

Figure II.11 shows each Market Participants’ 2008-2010 hourly price distribution. The data used in 

this analysis is the 90th percentile of hourly prices, meaning the prices outside of two standard 

deviations of the mean were excluded. Both price volatility and the system average price have 

increased from 2009. Congestion is the principal driver for both volatility and price extremes, and as 

indicated in this figure, congestion and volatility affect certain participants to a larger extent than 

others. Average prices of zero indicate the Market Participant did not participate in the SPP EIS 

Market during that year. 

Figure II.11 Annual Price Range by Market Participant 

 

‐100.00

‐50.00

0.00

50.00

100.00

150.00

200.00

200820102009200820102009200820102009200820102009200820102009200820102009200820102009200820102009200820102009200820102009200820102009200820102009

AECC AEPMBEPM EDEPGMOCGRDX GSEC INDN KBPU KCPS KEPC KPP LESMMEANMIDW OGE OMPAOPPM SECI SPSM TEAN WFESWRGS SPP

Min Max Average
Southwest Power Pool, Inc.                    

SPP 2010 State of the Market Report 42

Average Monthly Prices 

Figure II.12 shows Market Participants’ average monthly price for 2008-2010. There was some 

significant deviation between Market Participants’ system prices. Differing prices are to be expected, 

as participants each have resource fleets and congested areas that behave differently. Differences 

between Market Participant prices in any given month likely indicate there was congestion in the 

affected region that caused this deviation. If congestion had not been present, prices experienced by 

all the Market Participants would have been identical. Constraints or congestion into or out of 

Market Participants’ areas cause price deviation and may lead to substantial differences in their 

average prices. 

Average price separation between Market Participants increased substantially from 2009, which is 

likely the result of specific transmission system limitations that led to increased congestion in certain 

areas. 

Figure II.12 Average Monthly Price by Market Participant 

0

10

20

30

40

50

60

70

80

90

100

JAN FEB MAR APR MAY JUN JUL AUG SEP OCT NOV DEC JAN FEB MAR APR MAY JUN JUL AUG SEP OCT NOV DEC JAN FEB MAR APR MAY JUN JUL AUG SEP OCT NOV DEC

2008 2009 2010

$/MWh

AECC AEPM BEPM EDEP GMOC GRDX GSEC INDN KBPU KCPS KEPC KPP

LESM MEAN MIDW OGE OMPA OPPM SECI SPSM TEAN WFES WRGS
Southwest Power Pool, Inc.                    

SPP 2010 State of the Market Report 43

Interval Price Excursions 

Interval prices are the most granular of all SPP EIS Market prices. The Market Operations System 

generates prices for all pricing nodes every five minutes, once for each market interval. These prices 

represent the value of energy at a particular point in the system for the interval. Market Participants 

are not exposed directly to these prices, as billing is settled on hourly values (a simple average of the 

hourly interval values). Nonetheless, interval prices that are either significantly higher or lower than 

the norm can indicate market limitations or bottlenecks. 

Interval prices shown in Figure II.13 are divided into four categories: (I) less than $0/MWh, (II) 

between $0-$100/MWh, (III) between $100-$400/MWh, and (IV) above $400/MWh. The 

percentage of pricing events for the listed categories is depicted. Prices higher than $400 or less than 

$0 generally indicate a market limitation. 

The $400/MWh price reflects the initial FERC bid cap that was in place for the first three months of 

EIS Market operations in 2007. The FERC cap has since been increased to $1,000/MWh. In 2010 

over 98% of interval prices were between $0-$100/MWh. Less than 1.0% were between $100-

$400/MWh. Approximately 1.5% of interval prices were below $0/MWh, and approximately 0.01% 

were above $400/MWh. 

Generally, 2010 pricing distribution falls well within expectations. Extreme pricing events denoted 

prices less than $0 or greater than $400 are infrequent, occurring less than 1% of the time. These 

pricing extremes are largely driven by severe transmission constraints or system ramp limitations, 

both of which are carefully monitored by the MMU. 

Figure II.13 Interval Prices beyond Threshold Levels for 2010 

Month

Percent of

Observations

Less than $0

Percent of

Observations

Between $0

and $100

Percent of

Observations

Between

$100 and $400

Percent of

Observations

Greater than

$400

January 0.79% 98.28% 0.79% 0.12%

February 0.25% 98.87% 0.67% 0.12%

March 2.31% 96.81% 0.75% 0.12%

April 2.68% 96.26% 1.04% 0.01%

May 2.21% 96.76% 0.75% 0.08%

June 0.85% 98.54% 0.47% 0.07%

July 0.43% 98.61% 0.92% 0.04%

August 1.00% 97.30% 1.33% 0.35%

September 1.85% 97.46% 0.63% 0.05%

October 0.85% 98.69% 0.39% 0.08%

November 1.27% 97.75% 0.81% 0.17%

December 0.67% 98.77% 0.43% 0.14%
Southwest Power Pool, Inc.                    

SPP 2010 State of the Market Report 44

Re-pricing Occurrence 

Interval prices from the Market Operations System may be revised if there are software or data input 

errors. Figure II.14 shows the percentage of hours per month that were re-priced in 2008-2010. An 

average of approximately 3% of all hours were re-priced in 2010, a substantial decline from 2009 

when approximately 5% were re-priced. This is an important issue because the re-priced periods 

represent time when the market is running at less than optimal efficiency. 

 

Figure II.14 Percent of Re-priced Hours by Month from 2008 – 2010 

0%

2%

4%

6%

8%

10%

12%

Jan

Feb

Mar

Apr

May

Jun

Jul

Aug

Sep

Oct

Nov

Dec

Jan

Feb

Mar

Apr

May

Jun

Jul

Aug

Sep

Oct

Nov

Dec

Jan

Feb

Mar

Apr

May

Jun

Jul

Aug

Sep

Oct

Nov

Dec

2008 2009 2010

Percent of Hours Repriced
Southwest Power Pool, Inc.                    

SPP 2010 State of the Market Report 45

2010 Price Contour Map 

A final look at prices is provided in Figure II.15, which depicts the 2010 price contour map. This 

figure is a visual depiction of the price differential that resulted from congestion; it was calculated by 

average prices at each pricing node for the year. 

There was significant, prolonged congestion at six distinct locations. For a detailed list of the 

flowgates that correspond with these areas, refer to Figure II.16, Principal Congested Flowgates by 

Area. 

For the fourth year, the Texas panhandle is the most congested area in the SPP region. There are 

several explanations for this, leading to a fundamental conclusion that the lack of available 

transmission capacity in this region has serious implications for local market efficiency and the 

potential for local market power. A more recent development is persistent lower prices in Nebraska, 

which are also due to transmission limitations in the form of limited export capability; such 

limitations tend to lead to lower average prices. 

Figure II.15 2010 Price Contour Map 

500 kV

345 kV

230 kV

161 kV

138 kV

115 kV

69 kV

Oklahoma City

Texas Tulsa

Panhandle 

Wichita 

Area 

SE Kansas 

Kansas 

City 

Area 

SW Kansas

SE Oklahoma
Southwest Power Pool, Inc.                    

SPP 2010 State of the Market Report 46

Principal Congested Flowgates 

Congestion in the SPP system is largely concentrated in a few select corridors that correspond to 

macro power flows across the region. For instance, the Texas panhandle is heavily congested due 

largely to overall flows from the rest of the system into this region. Congestion in the Kansas City 

area is driven principally by north to south flows that occur in the Nebraska/Kansas interface. Other 

major congested areas have different characteristics, but tend to be derived from a larger system 

trend than a localized issue. 

Figure II.16 shows the most congested areas and their associated flowgates. Several flowgates may 

correspond with any given congested interface. Also included are proposed transmission solutions 

that would help in some way alleviate the congested element, as proposed by SPP Transmission 

Planning. 

Figure II.16 Principal Congested Flowgates by Area 

Region Flowgate Name

Flowgate 

Location (kV)

Average 

Hourly 

Shadow 

Price 

($/MWh)

Total % 

Intervals 

(Breached 

or Binding)

Projects Expected to Provide Some 

Positive Mitigation (Estimated In 

Service Date – Upgrade Type)

1. Rebuild Randall Co–Palo Duro 115 kV line (April 

2014 - no NTC but is Sponsored)

2. Tuco Int. – Woodw ard 345 kV line (May 2014 - 

Balanced Portfolio)

3. Sw isher Co. Int. – New hart 230 kV line (April 

2015 - Regional Reliability)

1. Tuco Int. – Woodw ard 345 kV line (May 2014 - 

Balanced Portfolio)

2. Castro County Int. – New hart 115 kV line (April 

2015 - Regional Reliability)

1. Tuco Int. – Woodw ard 345 kV line (May 2014 - 

Balanced Portfolio)

2. Tw o Hitchland – Woodw ard 345 kV lines 

(June 2014 - Priority Projects)

1. Rose Hill – Sooner – Cleveland 345 kV lines 

(Dec 2012 – Regional Reliability/Balanced 

Portfolio)

2. Tw o Woodw ard – Medicine Lodge – Wichita 

345 kV lines (Dec 2014 - Priority Projects)

SE Oklahoma LONSARPITVAL

Lone Oak to 

Sardis [CSWS] 

(138) ftlo Pittsburg 

– Valiant [CSWS] 

(345) $11.36 2.70%

1. Sunnyside – Hugo – Valliant 345 kV line (April 

2012 - Transmission Service)

1. Axtell–Post Rock–Spearville 345 kV line, tw o 

Spearville – Comanche – Woodw ard 345 kV 

lines, and tw o Comanche – Medicine Lodge – 

Wichita 345 kV lines (12/31/2014 - Balanced 

Portfolio/Priority Projects)

2. Iatan – Nashua 345 kV line (June 2015 - 

Balanced Portfolio)

3. Nebraska City – Maryville – Sibley 345 kV line 

(June 2017 - Priority Projects)

1. Iatan – Nashua 345 kV line (June 2015 - 

Balanced Portfolio)

2. Nebraska City – Maryville – Sibley 345 kV line 

(June 2017 - Priority Projects)

LAKALAIATSTR

Lake Road – 

Alabama [GMOC] 

(161) ftlo Iatan to 

Stranger Creek 

[KCPL] (345) $7.70 1.80% Same as LAKALASTJHAW above

1. Rose Hill – Sooner 345 kV line (June 2012 - 

Regional Reliability)

2. Tw o Woodw ard – Comanche Co. – Medicine 

Lodge – Wichita 345 kV lines (Dec 2014 - Priority 

Projects)

SW Kansas HOLPLYHOLSPE

Holcomb – Plymell 

Sw itch [SECI] 

(115) ftlo Holcomb 

- Spearville [SECI] 

(345) $6.31 1.90%

1. Rebuild Holcomb – Plymell Sw itch 115 kV line 

(Dec 2011 - Regional Reliability)

PLAKCISTRCRA

Platte City – KCI 

(161)[GMOC] ftlo 

Stranger Creek – 

Craig (115) [KCPL] $9.27 1.40%

Wichita Area ELPFARWICWDR

El Paso – Farber 

[WR] (138) ftlo 

Wichita – 

Woodring [WROGE] (345) $7.50 4.30%

SE Kansas NEOCOLNEODEL

Neosho - 

Columbus [WREDE] (161) ftlo 

Neosho - 

Delaw are (345) $10.45 4.30%

Kansas City Area

LAKALASTJHAW

Lake Road – 

Alabama [GMOC] 

(161) ftlo St. Joe – 

Haw thorn [GMOC] 

(345)

$9.94 1.60%

15.30%

OSGCANBUSDEA

Osage Sw itch - 

Canyon East [SPS] 

[(115) ftlo 

Bushland - Deaf $23.09 16.40%

SHAXFRTUCOKU

Shamrock XFR 

[CSWS] (115/69) 

ftlo Tuco – 

Oklaunion [SPS- $4.36 3.00%

Texas Panhandle

RANPALAMASWI

Randall County - 

Palo Duro (115) 

ftlo Amarillo – 

Sw isher (230) 

[SPS] $23.83 
Southwest Power Pool, Inc.                    

SPP 2010 State of the Market Report 47

Summary and Conclusions

During 2010, congestion in the SPP region followed similar patterns as in 2009. Principal congested 

corridors and their associated flowgates were largely unchanged. This is not unusual, as transmission 

construction to address the congestion is a lengthy process; once development is necessitated it may 

be some time before completion. 

The MMU is encouraged by continued transmission development throughout the SPP region. This 

development will increase the efficiency and effectiveness of the SPP EIS Market and markets added 

in the future. The MMU is concerned about the lack of progress in dealing with the sustained high 

level of congestion in the Texas Panhandle area of the SPP market. 
Southwest Power Pool, Inc.                    

SPP 2010 State of the Market Report 48

D. Revenue Adequacy (Cost Recovery Determination)

An important theory of economic efficiency in markets is the notion that outcomes via pricing 

schemes should reflect full cost recovery. If market prices do not reflect full cost recovery, new 

entrants will not be incentivized to move into the market. If prices reflect full cost recovery, new 

participants will enter the market to profit from the economic rents. In the case of electricity markets, 

prices that reflect full recovery cost indicate that system demand is strong and additional generation 

is necessary. Prices that are continually below the full recovery cost indicate an excess of supply and 

additional investment in generation is not recoverable given economic conditions. 

Critical to the theory of full cost recovery is the baseline selection mechanism which determines the 

investment cost of new generation. To reduce the complexity of the baseline selection process, the 

SPP MMU made several simplifying assumptions and relied extensively on the Electricity Market 

Module published by the Energy Information Administration1

. Key assumptions from the 

Electricity Market Module can be found in Figure II.17. For this analysis, three technologies were 

selected that represent the most likely contribution to new generation capacity in the SPP region: 

Scrubbed Coal, Advanced Gas Combined Cycle, and Advanced Combustion Turbine. 

Figure II.17 Key Assumptions in Revenue Adequacy Formulation 

Determining the potential profitability of a new generating facility involves the following general 

process. For each hour, the estimated marginal cost as identified in Figure II.17 is compared to the 

system average price. If the estimated marginal cost is less than the system average price, the 

difference between these prices is calculated and multiplied by the size of the proposed facility as 

found in Figure II.16. By multiplying the difference between the system average price and the 

estimated marginal cost by the capacity of the unit, a total projected revenue stream can be 

established. This calculation is performed for each hour in the year and the result is summed.

 

1

 http://www.eia.doe.gov/oiaf/aeo/assumption/pdf/electricity.pdf#page=3 

Descriptor

Scrubbed

Coal

Advanced

Gas/Oil

Combined

Cycle

Advanced

Combustion

Turbine

Size (MW) 600 400 230

Base Overnight Cost ($/kw) 2078 897 617

Total Overnight Cost ($/kw) 2223 968 648

Variable O&M ($/Mwh) 4.69 2.04 3.24

Fixed O&M ($/kW/Year) 28.15 11.96 10.77

Heatrate (Btu/kWhr) 8740 6333 8,550
Southwest Power Pool, Inc.                    

SPP 2010 State of the Market Report 49

In Figure II.18 the actual return represents the potential revenue stream of a new generating facility 

using the above method. Comparing the actual return to the expected plant return determines if 

investment in a new generating facility is warranted. The expected plant return uses an assumed 

return on equity of 10%. 

For all fuel types, the actual return that could be expected from investment in new generation is not 

sufficient for full cost recovery. This does not mean there is no rationale for investment in new 

generation. Regulatory requirements, reliability demands, shifts in generation technology emphasis, 

and loading patterns may require new generation construction. What may be inferred is that 

generation additions from independent entrants based on purely economic incentives may not be 

warranted at this time. 

Figure II.18 Revenue Adequacy Results 

Figure II.19 shows revenue adequacy results in expanded detail. This table depicts the result of the 

revenue adequacy calculation using individual Market Participant price data instead of the system 

average price. This analysis determines if generation construction may be more advantageous at 

various points in the SPP system. There is a differential across the locations, which is expected as 

some areas experience significant transmission congestion and prices significantly different than the 

system mean. However, in every case projected revenues do not warrant new construction. This 

situation is as expected given the very large reserve margin in the SPP footprint shown in Section I.C 

Generation. 

Figure II.19 Revenue Adequacy Results for Select Market Participants 

 

System Price Comparison

Marginal

Cost

Actual

Return $

Expected Plant

Return $

(Deficiency)

or Excess $

Scrubbed Coal New 9.99 112,859,210 150,270,000 (37,410,790)

Adv Gas/Oil Combined Cycle 28.42 24,299,246 43,504,000 (19,204,754)

Adv Combustion Turbine 38.86 6,078,964 17,381,100 (11,302,136)

Scrubbed

Coal

Advanced Gas/Oil

Combined Cycle

Advanced

Combustion

Turbine

AEP ($31,467,038) ($16,495,858) ($10,328,867)

KCPL ($33,713,051) ($15,161,517) ($9,037,689)

NPPD ($53,063,719) ($23,466,579) ($12,317,558)

OGE ($34,048,404) ($18,578,845) ($11,535,479)

SPS ($21,726,838) ($12,157,465) ($8,417,733)

WR ($39,211,899) ($18,309,287) ($10,618,787)

(Deficiency) or Excess $

Selected Participant
Southwest Power Pool, Inc.                    

SPP 2010 State of the Market Report 50

E. Fuel Type

Generation by Fuel Type (percentages) 

Analyzing fuel types most utilized in the SPP EIS Market provides a better understanding of the 

pricing structure as well as the potential impact of environmental and other regulatory requirements 

in the SPP system. An understanding of fuel types and fleet characteristics enables the market to 

better manage and coordinate resource outages and maintain reliability during system emergencies. 

Figure II.20 depicts 2010 generation in the SPP EIS Market by fuel type. Coal is the predominant 

fuel source; in 2010, coal generation accounted for 62.49% of all generation in the SPP EIS Market. 

This was much greater than natural gas, the next most prevalent fuel type, which generated 22.61%. 

Traditionally, coal has been the largest source of energy in the SPP region, but recently gas 

generation has increased its total market share. There are several reasons for this. As gas prices 

decline, the relative cost of generation from this fuel declines in comparison with other fuels. In the 

long-term, it is anticipated that gas generation will substantially increase in both total capacity and 

market share. As coal generation continues to be impacted by regulatory issues, the percentage of 

generation derived from coal will decline. Whether there is a precipitous drop will depend on the 

eventual outcome of climate legislation and the magnitude of taxes that may be levied on coal 

generation. In the short-term, a resurgence of less expensive natural gas and the increased emphasis 

on developing wind generation will continue to yield changes as reflected in this table. 

Figure II.20 Percent Generation by Fuel Type for 2010 

Jan Feb Mar Apr May Jun Jul Aug

Coal 62.95% 65.43% 66.36% 62.43% 61.55% 58.73% 58.05% 57.52%

Gas 23.01% 20.99% 16.82% 18.62% 21.85% 27.79% 29.72% 31.46%

Nuclear 9.36% 9.62% 9.41% 10.90% 10.30% 8.04% 7.82% 7.31%

Wind 3.85% 2.90% 6.29% 6.93% 5.15% 4.40% 3.33% 3.13%

Hydro 0.76% 0.96% 0.99% 1.02% 1.05% 0.94% 0.99% 0.50%

Oil 0.00% 0.00% 0.00% ‐0.01% 0.00% 0.00% 0.00% 0.00%

Other 0.07% 0.10% 0.12% 0.11% 0.10% 0.10% 0.08% 0.09%

Total 100.00% 100.00% 100.00% 100.00% 100.00% 100.00% 100.00% 100.00%

(Continued) Sep Oct Nov Dec

2010

Average

2009

Average

2008

Average

Coal 61.57% 63.02% 66.59% 65.73% 62.49% 64.2% 65.7%

Gas 23.83% 22.57% 14.84% 19.86% 22.61% 23.0% 25.1%

Nuclear 9.30% 8.51% 10.94% 8.96% 9.21% 7.5% 4.6%

Wind 4.56% 5.32% 6.92% 4.97% 4.81% 4.3% 3.5%

Hydro 0.64% 0.46% 0.58% 0.39% 0.77% 0.9% 0.8%

Oil 0.00% 0.00% 0.00% 0.00% 0.00% 0.0% 0.0%

Other 0.11% 0.12% 0.12% 0.09% 0.10% 0.1% 0.2%

Total 100.00% 100.00% 100.00% 100.00% 100.00% 100.00% 100.00%
Southwest Power Pool, Inc.                    

SPP 2010 State of the Market Report 51

Generation by Fuel Type (graphical) 

Figure II.21 shows market resources’ total generation by fuel type in GWh for February 2007-

December 2010. Coal is the predominant source of energy in the SPP EIS Market region. Natural 

gas is a distant second, and other fuel types follow. This chart depicts the relative change in 

generation patterns by fuel over time. The cyclical nature of generation from certain fuel types is 

clearly visible. 

Figure II.21 GWh Generation by Fuel Type for 2010 
Southwest Power Pool, Inc.                    

SPP 2010 State of the Market Report 52

Generation on the Margin 

Figure II.22 displays which fuels are at the margin in SPP, thus setting market prices. The system 

marginal price is calculated as the price of the next MW available after the total system demand has 

been met. The Locational Imbalance Price (LIP) is the system marginal price plus any congestion 

charges associated with the pricing node. For a generator to set the system marginal price, the 

resource must: (a) be in “available” status, (b) not at the resource plan minimum or maximum, and 

(c) not ramp limited. 

As highlighted in Figure II.20, generation from coal-fired resources is responsible for over 60% of 

all generation in SPP. It is expected that coal would be the marginal resource for a significant 

amount of the time. However, coal resources in the SPP region are predominantly baseload units; 

they operate best at a constant output and are not used for load following as frequently as in some 

regions. 

During 2010, coal was on the margin 38% of the time and natural gas was on the margin 61.7% of 

the time. Natural gas units in the SPP region are consistently used for load following, and are 

therefore on the margin more frequently. 

If gas prices remain at their relatively low levels, an interesting phenomenon may develop regarding 

marginal fuel ratios. As fuel costs change, participants review their resource fleets and determine the 

most economical long term mix. As the relative gas to coal cost declines, participants may decide to 

add additional gas capacity to their fleets in lieu of coal. If this occurs, the marginal fuel will shift 

further away from coal and add to the already large gas total. 

Figure II.22 Generation at the Margin in 2010 

Fuel Type Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Total 2009 Total 2008 Total

Other 0.1% 0.0% 0.2% 0.5% 0.9% 0.3% 0.0% 0.2% 0.6% 0.2% 0.3% 0.1% 0.3% 0.1% 0.1%

Coal 29.9% 25.6% 41.9% 43.8% 46.7% 40.4% 32.0% 33.5% 40.7% 35.5% 44.4% 41.8% 38.0% 39.0% 30.4%

Gas 70.0% 74.4% 57.8% 55.7% 52.5% 59.3% 68.0% 66.3% 58.7% 64.4% 55.4% 58.1% 61.7% 60.9% 69.5%

Total 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0%
Southwest Power Pool, Inc.                    

SPP 2010 State of the Market Report 53

Wind Capacity and Generation 

The SPP region is an area of the country with a very high potential for wind generation, and wind 

investment and development continues throughout. Figure II.23 depicts capacity and total generation 

from wind facilities for December 2008-December 2010, in the SPP region. Total wind capacity 

increased by almost 700 MW in 2010. Total wind generation is also trending upward as more 

capacity is added. 

Figure II.23 Wind Capacity and Generation 

 

0

500

1,000

1,500

2,000

0

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

Wind Generation (GWh)

Wind Capacity (MW)

Wind Capacity (MW) Wind Generation (GWh)
Southwest Power Pool, Inc.                    

SPP 2010 State of the Market Report 54

F. Market Participation

Settling imbalances in the EIS Market is mandatory and automatic; however, full participation in the 

SPP EIS Market is voluntary. Market Participants must decide how to best manage their resources 

through appropriate scheduling, resource offers, and resource control parameters. Specifically, 

Market Participants may modify the control parameters of their resources by changing any or all of 

the following: dispatchable range, resource minimums, resource maximums, ramp rates, price offers, 

resource status, etc. The following charts and descriptions depict some key components of these 

parameters. 

Dispatchable Range 

Dispatchable range is a control parameter that allows resources to alter their total range of operation. 

If a unit has a 500 MW maximum and a 100 MW minimum output level, the dispatchable range is 

400 MW. If this resource were to add Spinning or Up/Down Regulation service to this resource, it 

would decrease the total dispatchable range by the amount of the service. Limiting the dispatchable 

range or resources diminishes the responsiveness of the EIS Market because it shrinks the total 

operational range over which resources may be moved. If the dispatchable range is very small, an 

increased incidence of extreme pricing events is likely because the market would not be able to 

respond to sudden market condition changes. 

Figure II.24 represents the dispatchable range of available resources for December 2008-December 

2010. There is a noticeable downward trend in the total dispatchable range available to the SPP 

system. This concerns the MMU. Adequate dispatchable range is an important characteristic of any 

successful market, and the lack of an adequate range can have severe repercussions. The MMU will 

continue to monitor the dispatchable range and weigh options for increasing it. 

Figure II.24 Dispatchable Range of Available Resources 

32%

36%

40%

44%

Avg Dispatchable Range / Peak Demand Linear (Avg Dispatchable Range / Peak Demand)
Southwest Power Pool, Inc.                    

SPP 2010 State of the Market Report 55

Ramp Rates 

Ramp rates play a key role in EIS market operations because they place limits on how quickly a unit 

can respond to changes in loading conditions or dispatch instructions. As load increases or decreases, 

units must move accordingly to maintain the proper balance between instantaneous supply and 

demand. Higher ramp rates allow units to move more rapidly and adjust more quickly to these 

changes. Lower ramp rates increase the total response time to changes in load. If ramp rates are too 

low, the market cannot respond quickly enough to changes in system load and ramp shortages will 

occur. Ramp shortages serve two functions: they indicate that there is not enough ramp from 

available resources in a specific location, and they provide incentives to Market Participants to 

provide sufficient ramp to maintain the most efficient system possible. 

Figure II.25 shows the average monthly available ramp per interval for December 2008-December 

2010 and the total monthly ramp deficiency intervals. The total available ramp increased slightly 

over time, with some noticeable seasonal patterns. More ramp is traditionally necessary during high 

loading seasons when the system is required to respond to large changes in load. Running countercyclically to the total ramp portion of the figure is the total number of ramp deficiency intervals. 

This also is to be expected, because if more ramp is available, there is less likelihood of a ramp 

deficiency. 

Figure II.25 Ramp Availability and Deficiency Intervals 

-

40 

80 

120 

160 

200 

240 

280 

320 

360 

400 

-

20 

40 

60 

80 

100 

MW Ramp Available per Minute

Ramp Deficiency Intervals

UP Ramp Deficiency Intervals DOWN Ramp Deficiency Intervals Total MW Ramp Available per Minute
Southwest Power Pool, Inc.                    

SPP 2010 State of the Market Report 56

Ramp and Capacity 

A composite view of ramp in the SPP EIS Market can be seen in Figure II.26, which shows ramp 

available to the system as standardized by available capacity, compared to the average online 

capacity. The total standardized system ramp remained fairly constant across time, although there is 

a slight downward trend. Sufficient ramp is vital to ensure proper market operation. There was 

speculation that as participants became more comfortable with the market, they would increase 

participation by increasing their ramp rate and other control parameters. This does not appear to have 

happened. Because of the vital nature of sufficient ramp rate, the MMU will continue to carefully 

monitor this metric to ensure the market can maintain its efficiency and effectiveness. 

Figure II.26 Ramp and Average Online Capacity 

-

10 

20 

30 

40 

0.5

0.6

0.7

0.8

0.9

1.0

1.1

1.2

1.3

1.4

MW / Minute / 100 MW of Online Capacity

Average Online Capacity (GW) per Interval

Available Online Capacity MW / Min Offered / 100 MW of Online Capacity
Southwest Power Pool, Inc.                    

SPP 2010 State of the Market Report 57

Status Type Utilization 

Another way a Market Participant can modify its resource control parameters is by selecting the 

status type listed in their resource plans. The status type indicates the manner in which the resource 

is allowed to function. There are five status types: available, unavailable, self-scheduled, manual, 

and supplemental. Only the available status type allows the market to fully utilize a resource by 

changing the resource output and allowing it to set the system price. Manual indicates the resource is 

uncontrollable. Manual status resources cannot set price and are dispatched according their last 

known output. Self-scheduled resources are dispatched according to their sum of schedules against 

the resource. For a resource in self-scheduled status, a Market Participant has essentially predetermined an output level, regardless of overall market conditions or operations. Unavailable status 

indicates the resource is offline and not available for use by either the market or the Market 

Participant. Supplemental status indicates the resource is offline but available to come online within 

ten minutes. Available status units are most useful to the market because they can respond to 

instructions and quickly resolve congestion and alleviate other operational constraints. 

Generation by Status Type 

Figure II.27 shows generation from resources operating in various status types. The vast majority of 

generation comes from market available resources; consequently, the market is able to resolve many 

operational constraints and operate quite efficiently. In this chart, manual status is divided into 

Manual (other) and Manual (intermittent). Intermittent resources are becoming more important in the 

EIS Market, and the status types were separated to ensure proper categorization of generation from 

these resources. A point of interest is the steady decline in Self-Dispatched generation. The MMU 

has made a concerted effort to discourage the use of Self-Dispatched status and is gratified to 

recognize the decline in the use of this status. 

Figure II.27 Generation by Status Type 

-

5,000 

10,000 

15,000 

20,000 

25,000 

GWh Production

Other Manual (other) Manual (intermittent) Nuclear Self-Dispatch Market Dispatch
Southwest Power Pool, Inc.                    

SPP 2010 State of the Market Report 58

G. Market Power Measurement and Mitigation

The system marginal price and corresponding Locational Imbalance Prices are derived from the 

offer curves submitted by Market Participants. Because these offer curves are the principal driver of 

overall system prices, it is necessary to carefully monitor participant offers to mitigate improper 

offer submissions. The MMU’s principal concern is that a Market Participant may submit offers that 

are substantially higher than what is appropriate, causing the market clearing price to increase above 

what is warranted. A Market Participant raising its generators’ offer curves above their actual 

marginal cost is an example of Economic Withholding. 

The SPP Market Monitoring Unit is directly charged by FERC with mitigating instances of 

Economic Withholding. Consequently, the MMU has developed screens and market behavior 

analysis tools that look for this type of activity. One tool is the SPP offer cap, a methodology in 

which offers are automatically capped given the following conditions: (a) congestion is present in 

the system, (b) resources are in a position to wield potential market power and their Generator to 

Load Distribution Factors are greater in magnitude than -5%, and (c) affiliate resources of any 

capped resource are also capped. The SPP offer cap comes into play only during times of 

congestion. Without congestion, competition between Market Participants eliminates potential 

market power abuse. 
Southwest Power Pool, Inc.                    

SPP 2010 State of the Market Report 59

Offer Cap 

An additional capping tool is the FERC offer cap, which limits the total magnitude of submitted 

offers. The current value of this cap is $1,000; no participant may submit an offer exceeding this 

value. The FERC offer cap applies to all resources at all times. Neither the FERC nor SPP offer caps 

are price caps. Prices are set through the use of the System Pricing and Dispatch model, which may 

yield prices greater than any individual capped offer. 

Figure II.28 shows the relative impact of FERC and SPP offer caps during 2010. The offer cap 

metric has been included in the annual State of the Market Report since the beginning of the EIS 

market. The MMU introduced a new metric related to the SPP offer cap, but this original metric is 

included here for comparison. 

The amount of time any resource is dispatched near the FERC cap is exceedingly small. On average 

a resource is dispatched near the FERC cap .0046% of the time. Resources are dispatched with the 

SPP cap imposed a far greater percent of the time. In 2010 this occurred on average 41.86% of the 

time. There is a substantial difference between the SPP cap being imposed and whether or not prices 

were mitigated. This difference is seen in the last column, which shows the percent of time resources 

were dispatched near the SPP cap. If a resource was capped via the SPP cap and dispatched at a level 

near the cap, it is likely that the resource was directly affected by the imposition of the cap. 

Assuming this is the case, on average only .0203% of resource intervals were impacted by the 

capping methodology. This is a very small percent of total time and indicates that Market Participant 

offers are typically well within acceptable limits. 

Figure II.28 Effect of FERC and SPP Offer Caps in 2010 

Although the data developed in Figure II.28 clearly shows the offer cap comes into play a very 

limited amount of time, the MMU has considered that this overstates the total effect of the offer 

Month

Percent of Available Resource

Intervals Disptached Near

FERC Cap

Percent of Available Resource

Intervals with SPP Cap

Imposed

Percent of Available Resource

Intervals Disptached Near SPP

Cap

Jan 0.0022% 35.64% 0.0026%

Feb 0.0064% 27.36% 0.0064%

Mar 0.0003% 47.86% 0.0031%

Apr 0.0000% 36.30% 0.0575%

May 0.0016% 38.42% 0.0987%

Jun 0.0145% 37.22% 0.0467%

Jul 0.0121% 49.08% 0.0223%

Aug 0.0140% 61.63% 0.0791%

Sep 0.0031% 49.62% 0.0580%

Oct 0.0002% 39.95% 0.0229%

Nov 0.0004% 32.81% 0.0095%

Dec 0.0010% 46.37% 0.0298%
Southwest Power Pool, Inc.                    

SPP 2010 State of the Market Report 60

cap. The scope of the original metric included the number of resource-intervals in which resources 

were available to the market and were dispatched above zero MW. This was used as the denominator 

in the calculation for the percentage of offer capped intervals. The metric in Figure II.29 considers 

all resource-intervals for the denominator, regardless of status, outage, or generation level. The 

numerator in the calculation of Figure II.29 is also different from that used in Figure II.28. The 

calculation considers the number of resource-intervals in which market power may exist. This 

happens when the resource is available to the EIS market and it is pivotal to an activated 

flowgate. The Security Constrained Economic Dispatch (SCED) solution uses these conditions to 

determine if the submitted offer or the SPP offer cap is considered during LIP calculation. Although 

this happens rather often, it seldom affects dollars paid to the resource. A second measure is 

calculated to identify when 1) the offer is greater than the SPP offer cap, 2) the LIP is greater than 

the SPP offer cap, 3) the LIP is less than the offer, and 4) there is a non-zero imbalance volume (EIS 

energy was sold/bought at the LIP). Without all four conditions present, EIS dollars paid to this 

resource are not affected. The methodology used in Figure II.28 indicates that the SPP offer cap 

affected payments 137 times out of a million, whereas the methodology from Figure II.29 indicates 

the SPP offer cap affected payments only 3 times out of a million. 

Figure II.29 Effect of SPP Offer Caps in 2010 

Month % Market Power

Intervals

% Mitigated

Intervals

Jan‐10 9.44% 0.000000%

Feb‐10 6.80% 0.000100%

Mar‐10 10.61% 0.000100%

Apr‐10 7.58% 0.000800%

May‐10 9.01% 0.000500%

Jun‐10 11.78% 0.000800%

Jul‐10 16.21% 0.000100%

Aug‐10 21.42% 0.001400%

Sep‐10 13.48% 0.000200%

Oct‐10 8.97% 0.000000%

Nov‐10 6.66% 0.000000%

Dec‐10 11.27% 0.000100%

2010 Average 11.17% 0.000338%
Southwest Power Pool, Inc.                    

SPP 2010 State of the Market Report 61

Herfindahl-Hirschman Index (Market Participant Capacity) 

The Herfindahl-Hirschman Index (HHI) is a common measure of competitiveness used to identify 

relative levels of market concentration. The U.S. Department of Justice is a predominant user of the 

HHI as part of its approval process for mergers or acquisitions. A HHI at or under 1,000 is 

traditionally considered to be competitive and/or un-concentrated. A HHI between 1,000 and 1,800 

indicates moderate concentration, and/or a workably competitive solution. A HHI over 1,800 is said 

to indicate a highly concentrated market, and is unlikely to be competitive. In the case of electric 

markets, a higher level of 2500 is accepted as an upper threshold level. 

Figure II.30 shows the Herfindahl-Hirschman index for 2007-2010 calculated from total generation 

capacity shares. The HHI has declined as more Market Participants have been added to the EIS 

Market footprint. HHI values at this level indicate that no individual Market Participant can 

dominate the market and that the overall market is very competitive. This does not preclude the 

possibility of localized market power concerns, but does indicate that an individual participant is 

unlikely to successfully manipulate the system by withholding capacity. 

Figure II.30 Herfindahl-Hirschman Index (Market Participant Capacity) 

Herfindahl-Hirschman Index (Uncommitted Capacity) 

Figure II.31 shows the Herfindahl-Hirschman index for the years 2007 through 2010 for 

uncommitted capacity by market participants. Uncommitted capacity is calculated as the installed 

capacity at the summer peak minus the maximum load obligation. In the case of an independent 

power producer, the entire capacity is considered as uncommitted. As can be seen in the figure, the 

HHI values generally trend downward across time as more participants are added. 

Figure II.31 Herfindahl-Hirschman Index (Uncommitted Capacity) 

2007 1190

2008 1276

2009 970

2010 954

Herfindahl - Hirschman Index 

2007 969

2008 1133

2009 883

2010 810

Herfindahl-Hirschman Index
Southwest Power Pool, Inc.                    

SPP 2010 State of the Market Report 62

The Market Participant Capacity and Uncommitted Capacity calculations of the HHI yield similar 

results. At the start of the EIS Market both indexes show competitive market conditions. There was a 

slight increase in the HHI values in 2008 as system reconfigurations occurred. However, in both 

2009 and 2010, the HHI values have declined markedly. This clearly shows that during times of no 

congestion, that the market is workably competitive and that individual market participants are 

unlikely to be successful by withholding either capacity or uncommitted capacity. 

Wholesale Uncommitted Capacity 

The wholesale market capacity metric is a measurement of the uncommitted capacity in the market 

held by each market participant. FERC uses this measure as one of the screens for Market Based 

Rates authorization. If a market participant has control of less than 20% of the total uncommitted 

capacity, then they pass this market power test. 

The uncommitted capacity is the market capacity remaining after subtracting any capacity that is 

committed to serving contracted load; for the purposes of this calculation contracted load is defined 

as that derived under franchise load obligations. Firm sales to other parties are normally included in 

this calculation but not included here because this information is not readily available to the MMU. 

Figure II.32, Uncommitted Capacity Market Shares 2010, clearly highlights the limited impact 

attributable to individual market participants. Moreover, as no individual market participant passes 

the 20% threshold of uncommitted capacity, there is little likelihood of market power and therefore 

the market in an unconstrained state is workably competitive. 

Figure II.32 Uncommitted Capacity Market Shares 2010 

0%

2%

4%

6%

8%

10%

12%

14%

16%

18%

20%
Southwest Power Pool, Inc.                    

SPP 2010 State of the Market Report 63

H.  Revenue Neutrality Uplift

SPP is required by its tariff to remain revenue neutral in its market operations processes. The total 

money paid to Market Participants for a given hour must equal the amount collected from Market 

Participants. Market operations may result in instances in which there is a difference between net 

values either paid or collected by SPP. Should this occur, SPP must either uplift the deficiency to all 

Market Participants or distribute the over-collection back to Market Participants by including an 

adder in the hourly settlement. 

There are five components to Revenue Neutrality Uplift (RNU) (a) Energy Imbalance Service (EIS), 

(b) self-provided losses (SP loss), (c) over-scheduling charges (O/S), (d) under-scheduling charges 

(U/S), and (e) uninstructed deviation (UD) charges. Positive numerical results represent an overcollection by SPP and a payment to Market Participants. Negative numerical results represent an 

under-collection by SPP and require a payment from Market Participants. EIS results may be either 

positive or negative; SPP may either under or over collect depending on market results. Selfprovided losses may also be positive or negative, depending on the nature of the market solution. 

Over-scheduling charges, under-scheduling charges, and uninstructed deviation charges are always 

levied against Market Participants, which means they will always be negative in the corresponding 

chart. 

Energy Imbalance Service Payments 

EIS payments are calculated as EIS volume in MWh multiplied by the appropriate price at the settlement 

location (LIP). EIS volume is the difference between the metered MW value and the scheduled MW 

value. The LIP used is the appropriate settlement location LIP. For a given operating hour, the EIS 

component is the net of all sales and purchases. If SPP collects less revenue from Market Participants 

than it paid out, the EIS component of RNU is positive. Positive RNU is an indicator that SPP has a 

revenue shortfall and must collect additional revenue from Market Participants to remain revenue 

neutral. If SPP collects more revenue than it paid, the EIS component of RNU is negative and SPP has a 

surplus, which must be distributed back to Market Participants in order to remain revenue neutral. 

Self-Provided Losses 

Transmission losses are a reality of the electrical grid and must be accounted for when considering power 

flows throughout the SPP region. Losses associated with transactions wholly within the SPP region are 

already accounted for using the SPP EIS Market. Losses associated with transactions that source from a 

non-SPP region and sink into SPP are also accounted for using the SPP EIS Market. Losses from 

transactions that source within SPP and sink outside of SPP, and losses from transactions that both 

source and sink outside of SPP but travel through the SPP region, must be accounted for using an 

alternate method to the SPP EIS Market. 

There are two ways Market Participants may handle losses for the aforementioned transactions. They 

may settle these losses financially, or they may self provide the loss amount. Financial settlement of 

losses requires the Market Participant to pay for all loss costs associated with the transaction. If a Market 

Participant chooses to self-provide for its losses, the Market Participant assigns a Designated Balancing 

Authority, which is billed the loss amount times the LIP. The Transmission Owners are then 
Southwest Power Pool, Inc.                    

SPP 2010 State of the Market Report 64

compensated for the loss costs as a result of the transaction based on their LIP prices and the 

Transmission Owner Loss Matrix (posted on the Open Access Same-time Information System). If these 

amounts are not equal, RNU is necessary for SPP to remain revenue neutral. 

Over and Under Scheduling 

Over scheduling happens when a Market Participant schedules more load than actually occurs in its area 

in an attempt to profit from price differentials between its resource and load LIP values. Under 

scheduling happens when a Market Participant schedules less load than actually occurs to profit from 

price differentials between its load and resource LIP values. To mitigate under scheduling, SPP’s market 

software looks for instances in which a Market Participant’s actual load exceeds its scheduled load by 

4% or 2 MW, whichever is greater. Additionally, the Market Participant must have a LIP value at its load 

settlement location that is less than the LIP value at its generators. If these conditions are met, the 

software automatically calculates the total amount to be disgorged from the Market Participant. The over 

scheduling logic works in much the same way. If the Market Participant’s actual load is greater than the 

scheduled load by 4% or 2 MW, whichever is greater, and LIP at the generators is less than LIP at the 

load, the Market Participant is subject to disgorgement of any undue revenue. 

The Over and Under Scheduling charges outlined above were established to automatically mitigate 

instances of either over of under scheduling. These charges are levied against the Market Participant’s 

meeting the listed criteria and are distributed to all Market Participants according to the established RNU 

procedures. Under and over scheduling penalties are shown in the following RNU table as negative 

values because they are penalties levied against Market Participants and require payment from the same. 

Uninstructed Deviation Charge 

Uninstructed Deviation (UD) is the difference between a Market Participant resource’s dispatch 

instruction and actual output for a given interval. Market Participants are expected to operate their 

resources within an allowable tolerance range. Deviation from this range can cause adverse market 

impacts, as the market must adjust to resources not being where they were instructed. 

The tolerance range for a resource is set at 10% above and below the dispatch instruction, limited to a 

lower limit of 5 MW, and an upper limit of 25 MW. Up and Down Regulation is then added to the 

tolerance range to determine a total allowable deviation range for the resource. 

Deviation outside the total allowable deviation range is charged against the Market Participant. If the 

deviation is between zero and 25 MW, the charge is (MW deviation amount * LIP * 10%). If the 

deviation is greater than 25 MW, the charge is the sum of the previous calculation for 25 MW plus 

(deviation in excess of 25 MW * LIP * 25%). The absolute value of the interval deviation as calculated 

previously is then averaged across the hour for each resource. This yields the hourly uninstructed 

deviation total. Uninstructed deviation charges are levied against Market Participants and represent a 

payment required from the participant to SPP in the RNU chart. 
Southwest Power Pool, Inc.                    

SPP 2010 State of the Market Report 65

RNU Results 

Figure II.33 shows the total RNU for each month in 2010 by component. RNU derived from EIS 

represents the majority of total RNU. In 2010, EIS represents approximately 73% of total RNU. Positive 

RNU results in SPP applying an uplift procedure to collect additional money to remain revenue neutral. 

Negative RNU results in SPP distributing excess money back to Market Participants. 

High positive RNU may be the result of hedging instruments being left in place that are greater than the 

flowgate’s simultaneous feasibility capability. If this occurs, the total cost of congestion is not fully 

reflected, and significant uplift is necessary to cover any operational shortfall. RNU that results from 

this situation may be somewhat ameliorated by a more thorough curtailment of schedules that affect the 

constrained element. Additional curtailment causes the economic burden of constrained power flow to be 

distributed to the participants that are causing the constrained condition, which limits the need for 

additional RNU. 

Figure II.33 Components of RNU by Month for 2010 

‐2500

‐2000

‐1500

‐1000

‐500

0

500

1000

1500

2000

2500

3000

Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec

$ (in thousands)

EIS O/S U/S UDC SP LOSS
Southwest Power Pool, Inc.                    

SPP 2010 State of the Market Report 66

All-in Price 

Figure II.34 shows the all-in price by month for 2010. The all-in price is the load weighted SPP average 

price adjusted for net RNU. The net RNU adjustment is the total RNU divided by total EIS MWh. Even 

though total RNU may appear to be a substantial number, in the context of total EIS it is quite small. The 

largest negative RNU adjustment was $-.54/MWh in December 2010, a approximately 2% adjustment to 

the system average price. The largest adjustment was $.74/MWh in April 2010, an adjustment of 

approximately 3% in the total system average price. The magnitude of RNU adjustment does not cause 

the MMU to be concerned. 

 

Figure II.34 All-In Price by Month for 2010 

Month Energy (LIP) + RNU = All‐In Price

Jan 42.18 ‐0.42 41.76

Feb 40.56 0.44 41.00

Mar 27.72 0.12 27.84

Apr 27.06 0.74 27.80

May 27.69 0.38 28.07

Jun 33.05 ‐0.28 32.77

Jul 34.75 ‐0.20 34.55

Aug 35.92 ‐0.11 35.82

Sep 26.82 ‐0.27 26.55

Oct 25.89 0.00 25.89

Nov 24.63 ‐0.34 24.29

Dec 30.08 ‐0.54 29.54
Southwest Power Pool, Inc.                    

SPP 2010 State of the Market Report 67

Net versus Absolute EIS Payments Uplift  

The EIS Net RNU is a reflection of the amount of revenue that is given out or collected from market 

participants on an hourly basis for just the EIS payments portion of the Revenue Neutrality Uplift 

calculation. Each hour positive and negative imbalance is uplifted by market participant; positive 

uplift in a given hour may offset negative uplift from a different hour. To counteract this effect, the 

absolute RNU is shown in Figure II.35. As can be seen in the figure, the total magnitude of EI from 

both positive and negative accumulation is clearly visible. It is important to note that even in months 

when the monthly net impact is near zero, the actual hourly absolute RNU may be substantial. Both 

measures of RNU calculation and display show a noticeable decline in RNU since the start of the 

market and indicate an improvement in the efficiency of the market. There is a long term downward 

trend in Net EIS RNU. This indicates more costs are being allocated to actions and entities that are 

causing the cost and an indication that the overall efficiency of the market is improving. 

Figure II.35 Monthly Net vs. Absolute Energy Imbalance Revenue Neutrality Uplift 2007-2010 
Southwest Power Pool, Inc.                    

SPP 2010 State of the Market Report 68

III. Energy Delivery 

A. Transmission Service

The SPP Regional Transmission Organization is obligated by FERC to manage and regulate the flow 

of energy across the transmission system within its territory. SPP member companies have agreed to 

allow SPP to administer their component transmission systems and place these transmission facilities 

under provisions of the SPP Open Access Transmission Tariff. The Tariff contains regulations that 

describe how Market Participants are paid for use of the transmission system, as well as rules 

pertaining to use of the transmission system itself. 

Participants that wish to use the transmission system must follow specific provisions outlined in 

SPP’s Tariff, Market Protocols, and Business Practices. Market Participants work with SPP to ensure 

the maximum amount of transmission service requests are approved, while maintaining system 

reliability and security. Changes in demand patterns via transmission system flows can indicate 

larger economic shifts or transmission system modifications. The following metrics detect these 

types of changes. 
Southwest Power Pool, Inc.                    

SPP 2010 State of the Market Report 69

Transmission Owner Revenue 

Members that own transmission elements in the SPP system are entitled to revenues from use of 

those elements as facilitated by SPP. Figure III.1 shows total 2010 revenue generated from use of the 

transmission system. Total 2010 revenue was approximately $630 million. EIS Market revenues 

from purchases and sales totaled approximately $1.3 billion, which means transmission revenues 

were 50% of total system revenue. 

Figure III.1 Transmission Owner Revenue for 2010 

0

10

20

30

40

50

60

70

Jan‐10 Feb‐10 Mar‐10 Apr‐10 May‐10 Jun‐10 Jul‐10 Aug‐10 Sep‐10 Oct‐10 Nov‐10 Dec‐10

$ (in Millions)

Month
Southwest Power Pool, Inc.                    

SPP 2010 State of the Market Report 70

Transmission Service Requests by Year 

Transmission service requests provide a measure of the use of the transmission system. A 

participant’s request for service indicates its desire to use specific transmission system paths. The 

rate of confirmation of initial requests may represent the demand for access to the grid, and may also 

provide insight into the grid’s ability to simultaneously accommodate demand for transmission 

paths. 

Figure III.2 depicts 115,000 transmission service requests in 2010, a slight increase from 2009 but 

well below the long-term average. This number represents requests that were approved, modified or 

rejected. 

Figure III.2 Annual SPP Transmission Service Requests 

There has been speculation as to why there was a marked decline in the number of transmission 

service requests from 2007-2008 and 2008-2009. To better understand this issue a preliminary 

review was performed which identified the following possibilities for the decline in transmission 

reservations: severe economic downturn, restructuring and reorganization of entities involved in 

wholesale power transactions, changes in the price of natural gas and the incentive structure for gas 

generation sales, increased reliance on the market and market mechanisms to automatically provide 

short term energy needs. 

0

20000

40000

60000

80000

100000

120000

140000

160000

180000

2007 2008 2009 2010

Total Requests
Southwest Power Pool, Inc.                    

SPP 2010 State of the Market Report 71

Any number of the above reasons may be contributing factors to the overall decline in transmission 

service requests. However, after careful consideration, the principal drivers are likely a combination 

of severe economic impacts affecting power trading entities, and the acceptance and reliance on 

market mechanisms that supplant the need for separate scheduling schemes. Consequently, the 

MMU does not think that this poses any sort of structural manipulation or is in any way adversely 

affecting the transmission market. 

Transmission Service Requests by Status 

A more nuanced view of transmission service requests incorporates monthly values to better reflect 

intra-year changes that have occurred. Figure III.3 shows total transmission requests by status type 

for January 2007- December 2010. Total transmission service requests increased slightly in 2010 

from relatively stable levels in 2009, following substantial declines in late 2007 and mid-2008. A 

large decline in total transmission service requests is not worrisome in this case. The SPP EIS 

Market began operation in February 2007, and many Market Participants likely reduced their total 

requests as their comfort with market operations increased. 

Figure III.3 Monthly SPP Transmission Service Requests by Status from 2007 – 2010 

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SPP 2010 State of the Market Report 72

Approved and Refused Transmission Service Requests 

Modifying the above chart by removing the “Other” status generates Figure III.4, Monthly Approved 

and Refused Transmission Service Requests 2007–2010. The percentage of approved transmission 

service requests declined steadily during 2010, largely due to the sharp increase in refused 

transmission requests. The increase in refused requests is largely attributable to congestion. This is 

not necessarily a bad condition, because congestion resulting from full utilization of the transmission 

system is a natural consequence of the current market structure. If paths are fully utilized, market 

efficiencies are maximized and the largest possible benefit is derived from both the transmission grid 

and market operations. 

Figure III.4 Monthly Approved and Refused Transmission Service Requests from 2007 – 2010 

 

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SPP 2010 State of the Market Report 73

B. Transmission Congestion

An important consideration in analyzing overall market health is to study the use or overuse of the 

transmission system. In an ideal world, the transmission system would be robust enough to allow the 

transfer of any amount of energy to any point on the system, eliminating the possibility of 

congestion. However, building such a robust grid would be extremely expensive and costs would 

more than offset net gains for the interconnected system. The current transmission system balances 

energy transfer needs and overall affordability. The transmission system is reasonably efficient at 

facilitating energy transfers across the system, but it does yield congestion under certain conditions. 

Flowgates are used to monitor the transmission system to ensure proper operation and maintain 

maximum efficiency. A flowgate is a transmission element or combination of elements representing 

a piece of the transmission system over which energy flows must be monitored and controlled. SPP 

manages total system flows over these flowgates to control and manage congestion. 
Southwest Power Pool, Inc.                    

SPP 2010 State of the Market Report 74

Flowgate Congestion by Time (percentages) 

Figure III.5 shows the percentage of on-peak, off-peak, and total intervals in which there was at least 

one congested flowgate. In 2010, at least one flowgate was congested an average of 69% of the time. 

This is a slight decrease from 2009 in which an average of 71% of all intervals had at least one 

congested flowgate. Interestingly, congestion tends to occur during off-peak periods of the day. 

Traditionally, transmission congestion coincides with load increases throughout the day. Load 

normally increases in the morning, plateaus toward the middle of the day, then declines throughout 

the evening. More congestion during off-peak hours - 10 p.m. through 7 a.m. - indicates that 

something other than traditional load patterns is driving congestion. 

Figure III.5 Percent of Five-minute Intervals with at Least One Flowgate Congested 

Off Peak On Peak Total Off Peak On Peak Total Off Peak On Peak Total

Jan 26% 30% 28% 37% 33% 35% 52% 33% 44%

Feb 24% 27% 26% 63% 76% 69% 54% 48% 51%

Mar 68% 80% 74% 97% 91% 94% 90% 66% 78%

Apr 73% 74% 74% 81% 67% 74% 91% 77% 84%

May 53% 49% 51% 86% 92% 89% 79% 62% 72%

Jun 69% 77% 72% 85% 88% 86% 57% 62% 59%

Jul 73% 87% 80% 94% 86% 90% 57% 62% 59%

Aug 64% 82% 72% 91% 78% 85% 81% 79% 80%

Sep 36% 55% 45% 67% 43% 56% 82% 70% 76%

Oct 46% 55% 50% 60% 49% 54% 84% 61% 74%

Nov 66% 70% 68% 69% 40% 56% 90% 76% 83%

Dec 30% 22% 26% 73% 50% 62% 77% 61% 69%

Off Peak On Peak Total Off Peak On Peak Total Off Peak On Peak Total

Average 52% 59% 56% 75% 66% 71% 74% 63% 69%

2008 2009 2010

Month

2008 2009 2010
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SPP 2010 State of the Market Report 75

Flowgate Congestion by Time (graphical) 

Figure III.6 is a graphic representation of flowgate congestion as highlighted in Figure III.5. Overall 

congestion is trending upward, while the relationship between on-peak and off-peak congestion is 

inverting. Transmission congestion is not necessarily bad, as it may signal areas where additional 

transmission development is needed to eliminate bottlenecks and facilitate efficient use of system. 

Figure III.6 Percent congestion by Time Status 

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SPP 2010 State of the Market Report 76

Incidence of Flowgate Congestion

Another way to analyze transmission congestion is to study the total incidence of intervals in which 

a flowgate was either breached or binding. A flowgate is a monitored element of the transmission 

system that SPP uses to control overall loading and ensure the system reliability. A breached 

flowgate is one in which flow over the element has exceeded its allowable limit. A binding flowgate 

is one in which flow over the element has reached but not exceeded its allowable limit. 

Breached Flowgates 

Figure III.7, shows the total percent of intervals by month in which a flowgate was breached. The 

MMU is somewhat concerned that the level of breached intervals has in some months substantially 

exceeded 5%. Appropriate congestion management techniques should minimize the incidence of 

severe transmission congestion and preclude flowgate breaches of this extent. The MMU encourages 

SPP to better understand the cause of the excessive flowgate breaches and develop mechanisms to 

more efficiently deal with excessive congestion. 

Figure III.7 Intervals with Breached Flowgates 

 

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SPP 2010 State of the Market Report 77

Binding Flowgates 

Figure III.8 shows the total percent of intervals by month in which a flowgate was binding. The 

MMU is not as concerned about binding flowgates compared to breached, because binding flowgates 

may indicate that the transmission system is being fully utilized. A binding flowgate indicates the 

transmission system is functioning as efficiently as possible given its current condition and 

configuration. 

 

Figure III.8 Intervals with Binding Flowgates 

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SPP 2010 State of the Market Report 78

Constrained Flowgates by Time 

In the SPP region there are flowgates that are congested/constrained a significant amount the time. 

Figure III.9 lists the top 20 constrained flowgates in the SPP region. Three flowgates were 

constrained more than 10% of all intervals in 2010. While some congestion is necessary and 

provides important insight into transmission system limitations, congestion of this magnitude may 

reflect a deeper issue in the affected region. 

Figure III.9 Top 20 Time Constrained Flowgates 

FLOWGATE NAME

BINDING

INTERVALS

BREACHED

INTERVALS

TOTAL

INTERVALS

PERCENT

OF TIME

RANPALAMASWI 15689 377 16066 15%

TEMP01_15940 11849 389 12238 12%

SPPSPSTIES 11423 136 11559 11%

ELPFARWICWDR 5195 93 5288 5%

GENTLMREDWIL 5138 73 5211 5%

OSGCANBUSDEA 4948 45 4993 5%

TEMP26_16045 3465 293 3758 4%

SPSNORTH_STH 3332 28 3360 3%

SHAXFRTUCOKU 3059 92 3151 3%

KELSENEMACON 2797 203 3000 3%

LONSARPITVAL 2319 551 2870 3%

ELKXFRTUCOKU 2471 54 2525 2%

IASCLKNASJHA 2194 173 2367 2%

HOLPLYHOLSPE 1737 279 2016 2%

LAKALAIATSTR 1667 206 1873 2%

REDWILLMINGO 1377 44 1421 1%

TEMP14_16508 1196 122 1318 1%

TEMP10_16663 1146 63 1209 1%

COOPER_S 981 166 1147 1%

TEMP10_16439 873 202 1075 1%
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SPP 2010 State of the Market Report 79

Constrained Flowgates by Shadowprice 

Another way to look at the congestion effects from constrained flowgates is to quantify the dollar 

impact associated with relieving the congestion. A flowgate’s shadowprice represents the dollar 

value of flowgate relief, or the cost associated with relieving the congestion on the flowgate by one 

MW. Figure III.10 shows summed shadowprices for the listed flowgates categorized by binding or 

breached conditions. For example, for every 2010 interval in which there was a binding flowgate, its 

associated shadowprice is summed and the total displayed. 

Total shadowprices for some flowgates is quite high. High shadowprices indicate where additional 

investment is needed to relieve congestion. The results in Figure III.6 indicate that substantial 

investment in congestion relief mechanisms would greatly benefit the Texas panhandle and 

Shreveport areas. 

Figure III.10 Top 20 Constrained Flowgates by Shadowprice 

FLOWGATE NAME

BINDING

SHADOWPRICE

BREACHED

SHADOWPRICE

TOTAL

SHADOWPRICE

RANPALAMASWI 2,049,053 456,344 2,505,397

TEMP01_15940 1,590,901 437,543 2,028,445

LONSARPITVAL 378,951 814,793 1,193,745

TEMP26_16045 544,019 367,435 911,455

LAKALAIATSTR 463,131 346,813 809,943

ELPFARWICWDR 669,303 119,331 788,634

HOLPLYHOLSPE 265,714 398,078 663,792

TEMP10_16439 360,378 285,623 646,001

TEMP04_16564 238,144 338,571 576,715

TEMP25_16260 183,901 349,833 533,734

LAKALASTJHAW 136,482 374,753 511,235

TEMP03_16364 133,063 345,310 478,373

SHAXFRTUCOKU 323,665 134,498 458,163

KELSENEMACON 149,508 297,057 446,565

GENTLMREDWIL 306,569 100,702 407,272

OSGCANBUSDEA 368,844 30,060 398,904

PLAKCISTRCRA 135,295 193,318 328,613

TEMP14_16508 171,714 151,707 323,421

IASCLKNASJHA 93,243 214,877 308,120

IATXFRIATSTR 89,036 212,916 301,952
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SPP 2010 State of the Market Report 80

C. Transmission Outages

Transmission elements experience outages during which they are not in service and not available for 

use. Outages may be the result of maintenance or some other scheduled unavailability, or may be 

caused by unforeseen circumstances such as storm damage, accidents, fires, etc. 

Transmission Outage Days 

Figure III.11 shows total transmission outage days for 2004-2010. A transmission outage day is the 

total number of days in which a transmission element is out of service. For instance, if two 

transmission elements are out of service for one week, the number of transmission outage days 

would be {(2 elements * 7 days outage) = 14 transmission outage days}. 

The number of transmission outage days has increased dramatically. There are several reasons for 

this, including the addition of new market participants and new transmission elements to the SPP 

system. Reporting of transmission outages has increased, as there is an increased demand for 

accurate outage information. Construction of new transmission requires reworking existing elements, 

which necessitates outages. 

Figure III.11 Total Transmission Outage Days for 2004 through 2010 

 

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SPP 2010 State of the Market Report 81

At this time, the MMU is not overly concerned with the upward trend in transmission outages. 

Transmission outages may be trending upward for several reasons. Some indicators suggest that the 

market footprint has experienced increased maintenance on transmission lines. The region has also 

seen an increase in transmission upgrades. Although both of these reasons have short-term, negative 

impacts on congestion, they are both likely to have positive effects on the market in the long term. 

Over time, line maintenance and upgrades improve the integrity of the system and lessen overall 

congestion. From a market perspective, transmission outages only become a concern when a 

corresponding increase in congestion is observed. One indicator suggests that overall system 

congestion decreased slightly from 2009 to 2010 (see Figure III.5). However, the MMU will 

continue to closely monitor transmission outages and seek a clearer understanding of trends as more 

data become available. 

Transmission Outage Days by Month 

Figure III.12 shows days of transmission outage by month for 2004- 2010. Transmission and 

generator outages follow seasonal patterns; it makes sense to schedule transmission outages when 

there is less demand on the transmission system. 

Figure III.12 Days of Transmission Outage by Month for 2004 – 2010 

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SPP 2010 State of the Market Report 82

Transmission Outage Days by Balancing Authority 

Figure III.13 shows total days of transmission outages by Balancing Authority for 2010. The largest 

participants consistently experienced the most outage days. This is expected, because the largest 

participants have more transmission facilities and have more cause for outages. 

Figure III.13 Days of Transmission Outages by Balancing Authority 

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SPP 2010 State of the Market Report 83

Relative Repair Time for Transmission Outages 

Figure III.14 shows the ratio of transmission outage days compared to the number of transmission 

facilities by participant. This chart establishes the number of outage days per element by participant. 

The chart depicts considerable diversity because there is variability across the system and between 

participants. Outages in Market Participant areas may require different levels of remediation and 

may have vastly different methods of correction. 

Figure III.14 Ratio of Days of Transmission Outage Days to Number of Transmission Facilities 

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SPP 2010 State of the Market Report 84

D. Generator Outages

Generator outages typically fall into two categories, forced and maintenance. Forced outages occur 

when a generator is unable to function at full capacity due to an unforeseen circumstance, or it has 

otherwise been rendered inoperative. Maintenance outages occur when the owner schedules and SPP 

approves a generator or associated facility to be out for maintenance. Generator outages are 

interesting to the MMU because they may represent a classic case of physical withholding. The 

MMU closely monitors generator and transmission outages to ameliorate withholding of such type. 

Figure III.15 shows total forced and maintenance generation outages from 2008-2010. Also included 

is the percent of total generation experiencing an outage - the sum of maintenance and forced 

outages divided by the total daily capacity. Outages typically follow a seasonal pattern, with 

increased maintenance outages in spring and fall and increased forced outages during summer and 

winter. This is expected, as maintenance outages are traditionally scheduled during seasons when 

loading is low. Increased forced outages during peak loading seasons are also expected, because 

forced outages are more likely when more generation is online. The percent of outages also follows 

an expected seasonal pattern, with more outages occurring during low loading months. 

Figure III.15 Generation Outages (MW) by Status 

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FORCED OUTAGE MAINTENANCE OUTAGE PERCENT OUTAGE
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SPP 2010 State of the Market Report 85

E. Generation Interconnection (2010)

In order for generation to be added to the SPP footprint, it is necessary to perform engineering 

studies to determine the feasibility of the proposed generation connecting to the system and to 

identify any transmission development that is necessary to facilitate the proposed generation. Types 

of engineering studies include: Feasibility, PISIS, DISIS, and Facility. Generation under these study 

types is displayed in Figure III.16. Generation studies that have already been completed are also 

included in the figure. These include those interconnection agreements that are in the process or 

being created, those where work is progressing, and those where work has been suspended. 

Figure III.16 Generation Interconnection Requests by Category (MW) 

A very brief description of the study types and interconnection categories is provided below. 

•Feasibility Study Stage – Initial assessment of the practicality and cost involved in adding 

generation to the SPP transmission system. 

•Preliminary Interconnection System Impact Study (PISIS) – More detailed analysis of the 

proposed interconnection with cost allocations for necessary transmission upgrades (if any) 

•Definitive Interconnection System Impact Study (DISIS) - More detailed analysis of the 

proposed interconnection with cost allocations for necessary transmission upgrades (if any), 

and system response modeling with updated interconnection parameters 

•Facility Study Stage – Final analysis of proposed interconnection including detailed cost 

planning data, complete analysis of system integration impacts highlighting needed upgrades. 

•Interconnection Agreement (IA) Pending – The Customer, SPP and the Transmission Operator 

are in the process of negotiating aspects of the Generation Interconnection Agreement 

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SPP 2010 State of the Market Report 86

•Interconnection Agreement Fully Executed/On Schedule – A generation interconnection 

agreement has been executed and the construction of the facility as outlined in the agreement 

is underway 

•Interconnection Agreement Fully Executed/On Suspension - A generation interconnection 

agreement has been executed and the construction of the facility as outlined in the agreement 

has been suspended 

A reformulation of the generation interconnection requests in queue, summing by fuel type yields 

Figure III.17. As can be seen in the figure, Wind accounts for the vast majority of proposed 

generation interconnection, well over 19,000MW. Continued development of wind generation in the 

SPP region is very likely to continue and the proper integration of wind generation is fundamental to 

maintaining the reliability of the SPP system. Additions by other fuel types, while less than 

additions by wind, are still substantial and require careful planning to ensure proper integration into 

the regional grid. 

Figure III.17 Generation Interconnection Requests by Fuel Type (MW) 

 

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SPP 2010 State of the Market Report 87

F. Transmission Investment

SPP as a Regional Transmission Organization has a responsibility to develop transmission expansion 

plans that will ensure both the long and short term reliability of the system, as well as ensure that the 

system is cost effective and adequately robust. SPP has developed several Transmission Expansion 

Plans in past years, 2010 was no exception. The 2010 SPP Transmission Expansion Plan highlights 

many key areas of transmission development, and provides an outline of forecast capital outlays 

necessary to ensure that the transmission system remains adequate for both current and future needs. 

The 2010 SPP Transmission Expansion Plan (STEP) summarized needed transmission investments 

for the ten-year period from January 1, 2011 through December 31, 2021. Transmission expansion 

projects throughout the SPP region totaled more than $5.1 billion dollars of proposed development. 

Numerous projects are included; 3,295 miles of new transmission lines, 947 miles of reconductored 

transmission lines, 753Mvar of new capacitors, and over 100 new or upgraded transformers. 

Increasing the total transfer capability of the region is a principal consideration of this plan, as can be 

clearly seen by $3.5 billion allocated for the construction of new transmission lines. 

The MMU is delighted to see that the principal congested flowgates as published in both Annual and 

Monthly Market Reports have been reviewed in the 2010 STEP report and that consideration has 

been given to appropriate amelioration efforts for these congested areas. Additionally, the 

recognition that the current congestion experienced by market participants should be studied and 

where possible resolved is a major undertaking that should yield positive results for all parties. 
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SPP 2010 State of the Market Report 88

IV. Market Developments 

The following issues relate to the SPP market but are not directly represented by other metrics. This 

section highlights macro trends that may affect the SPP region, and discusses issues that may bring 

gains if new structures are adopted or incorporated. 

A. Integrated Marketplace Design Issues

The proposed Integrated Marketplace design is an extensive reform of SPP’s existing markets that 

will introduce a Day-Ahead Market with Transmission Congestion Rights (TCR), a Reliability Unit 

Commitment process, and a Real-Time Balancing Market. Beginning in September 2009, an MMU 

representative attended Market Working Group (MWG) meetings in which Marketplace design was 

discussed. The MMU discussed critical design elements internally and communicated recommended 

changes to the SPP Market Design team and MWG throughout the design process. Additionally, the 

MMU developed the Marketplace’s Market Monitoring Plan and Mitigation Measures. The 

following sections highlight the Integrated Marketplace design’s strengths and weaknesses, focusing 

on implications of the proposed rules’ efficiency and competitiveness. 

MMU Supports 

The MMU supports most of the proposed Integrated Marketplace design. The design includes 

several fundamental provisions that are key to increasing SPP’s market efficiencies and the regional 

benefits members receive from the Marketplace. Several of the issues listed below were highly 

debated and passed the MWG by a narrow margin. While aware of the dissenting members’ 

positions, the MMU supports the MWG’s votes and recommends including these elements in the 

SPP Integrated Marketplace design: 

(1) Five-minute settlement of the Real-Time Balancing Market 

(2) Operating Reserves Markets with co-optimization of energy and operating reserves 

(3) Operating Reserve Zones 

(4) Marginal Loss Method 

(5) Third party participation in the Transmission Congestion Rights market 

(6) Virtual Trading in the Day-Ahead Market 

These market design components will increase market efficiency, lead to competitive pricing, and 

induce competitive behavior from Market Participants. These components are based on fundamental 

economic principles that have been successfully implemented in other RTO markets. The MMU’s 

strong support of these market design elements is based on their sound theoretical grounding and 

successful practical application in other markets. 

MMU Concerns 

The MMU was opposed to the following design elements, and expressed its concern to both the 

MWG and the SPP Board of Directors. Consequently, the MWG has since reviewed these issues and 
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SPP 2010 State of the Market Report 89

has modified the market design by removing the provisions that supported these issues. 

Specifically, the MMU opposed: 

1) Restriction that the Reserve Zone minimum be no larger than the available reserves 

2) Rules that allow for the transfer of Reserve Zone obligations between Reserve Zones 

Restriction on the Reserve Zone Minimum

The Reserve Zone minimum was originally restricted to be less than or equal to the available 

reserves in a Reserve Zone. From the Market Protocols: 

...the Reserve Zone minimum Operating Reserve requirement is equal to the 

lesser of; 1) the difference between the largest Resource MW and unused 

import capability; 2) the difference between the Reserve Zone load and import 

capability; or 3) the sum of available Operating Reserve Resource MW within 

the zone whether the Resources are offered or not offered. 

As in other RTO markets, Reserve Zone minimums serve as triggers for scarcity pricing. If the 

available reserves in a Reserve Zone fall below the minimum requirement, there is a shortage of 

reserves and scarcity pricing is applied. Consider the following example: 

- In Reserve Zone A, the largest resource has a 500 MW capacity 

- The Reserve Zone load is 800 MW 

- The unused import capability is 100 MW and the sum of the available reserves is 300 MW: 

In the originally proposed language, the minimum Operating Reserve requirement was equal to the 

lesser of: 

1) The largest Resource MW (500 MW) – Unused import capability (100 MW) = 400 MW 

2) Reserve Zone load (800 MW) – Unused import capability (100 MW) = 700 MW 

3) Sum of Available Operating Reserve Resource MW within the zone = 300 MW

The Reserve Zone minimum would have been set equal to the amount of available reserves: 300 

MW. The reserves and unused import capability would sum to 400 MW, not enough to cover for the 

Import 

Capability 

(100 MW) 

Largest Gen (500 MW) 

Reserves 

(300 MW) 

Load (800 MW) 

Reserve Zone A 
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SPP 2010 State of the Market Report 90

loss of the 500 MW resource. Yet under the proposed protocol language, the minimum requirement 

would not exceed the available reserves and this will not be considered an operating reserve 

shortage. Prices would not reflect the shortage. 

In its Notice of Proposed Rulemaking that preceded Order 719, FERC noted that RTO/ISO market’s 

scarcity pricing rules may not produce prices that: 

 "accurately reflect the true value of energy [during periods of operating reserve 

shortages] and, by failing to do so, may harm reliability, inhibit demand response, 

deter new entry of demand response and generation resources, and thwart 

innovation."2

 

FERC continued in the same NOPR: 

"Without prices that reflect the true value of energy, we cannot expect the full 

integration of demand response into organized markets. We therefore do not 

believe that reforms in this area should be delayed until every barrier to demand 

response, whether retail or wholesale, technological or regulatory, is identified 

and addressed." 

Subsequently, in Order 719 FERC recommended four different approaches for applying scarcity 

pricing in RTO/ISO markets and required each RTO/ISO to implement scarcity pricing and better 

reflect the true value of energy during operating reserve shortages. 

The MMU argued that the restriction on the Operating Reserve zone minimum precluded the 

appropriate application of scarcity prices and effectively negated the beneficial price signals and 

efficiency gains that should be obtained through the use of Reserve Zones. 

Reserve Obligation Transfer Between Zones

In the originally proposed protocols, the Internal Reserve Zone Obligation Transfer Schedules would 

have allowed a Market Participant to transfer reserve obligations to a generator that is outside of the 

Reserve Zone. This provision, which to our knowledge is unique to SPP, could have created 

considerable inefficiencies in the energy and the TCR markets. 

Under these rules, inefficiencies could have arisen because the obligation transfer requires some 

assurance that the reserves, if called on, would be deliverable to the Reserve Zone where the 

obligation originated. If the reserves were not deliverable, inefficiency could have arisen in the 

Operating Reserve market because the market would no longer reflect the system’s physical realities. 

To ensure that reserves are deliverable, transmission capacity into the Reserve Zone would have 

 

2 Wholesale Competition in Regions with Organized Electric Markets, Notice of Proposed Rulemaking, 73 FR 12,576 

(March 7, 2008), FERC Stats. & Regs. 32,628 (2008), paragraph 107. 
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SPP 2010 State of the Market Report 91

been reduced by the amount of the obligation transfer. Thus, the restricted transmission capacity 

would not have been available for energy imports and congestion resolution. This would have 

reduced the effectiveness of the co-optimization of energy and reserves. This design element also 

would have presented potential market power abuse opportunities. This provision would have 

enabled a select group of members, those holding firm transmission rights between Reserves Zones, 

to lower the import capacity into a particular area. A lower import capacity would have increased the 

likelihood of congestion in the energy market and thus introduced gaming issues. 

This design element would have presented another problem related to the value of transmission 

rights. A Reserve Zone obligation transfer schedule required the Market Participant to possess firm 

transmission rights to deliver the reserves if called on. The value that accrued to the firm 

transmission rights holder would be obtained through the TCR Market. With the submittal of a 

reserve obligation transfer schedule, the Market Participant would have been reserving capacity and 

extracting additional value for holding the firm transmission rights. 

To summarize, prior to the removal of these design elements, the MMU had very serious concerns 

regarding Reserve Zone obligation transfers because of: 

• Inefficiencies in the energy market - Reserve Zone obligation schedules will occupy 

transmission capability that could be used to import energy into the constrained areas 

• Increased potential for gaming - Market Participants will have the ability to lower 

transmission capability that will increase the likelihood of congestion 

• Inefficiency in the TCR Market – Transfer schedules will reduce the transmission 

capability on the Reserve Zone interfaces, causing TCRs to be under-funded 

The benefit of internal reserve schedules is to hedge against differences in reserve costs between 

locations. The TCR Market will allow Market Participants to hedge these risks. Differences in 

reserve costs between two settlement locations should always be lower than the differences in energy 

costs due to the co-optimization of energy and reserves. Allocation of TCRs into the local Reserve 

Zone should provide protection for Market Participants seeking to hedge reserve cost differences 

Integrated Marketplace Design Status Update (April 2011) 

The SPP Markets and Operations Policy Committee (MOPC) endorsed the baseline Integrated 

Marketplace Protocols on January 12, 2011. The MOPC directed the MWG to proceed with a 

request to further evaluate the benefits of the SPP unique design elements, and to determine if the 

benefits were sufficient to overcome the associated implementation costs and risks. The MOPC and 

the SPP Board of Directors also requested that the MWG review and respond to the market design 

reports from the MMU and Boston Pacific, Inc (BPI). The MWG responded to the MOPC request 

with the submission of a written report on April 12, 2011. 
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The MWG concluded that no single existing market design could meet the full needs of the region. 

Furthermore, adopting a market design currently in use another RTO would not significantly reduce 

the costs of market implementation. 

The MWG review of the MMU and BPI recommendations produced the following modifications: 

1. Explicitly describe the process for adjusting the ARR nomination caps 

2. Remove the provision allowing the Reserve Zone internal obligation transfers 

3. Remove the provision allowing an operating Reserve Zone minimum to be equal to the 

available reserve amount 

The MOPC accepted and approved the modified design as recommended by the MWG on April 12, 

2011. One addition was made relating to the removal of enhanced combined cycle modeling. It was 

determined that this capability was to be added to the market within one year of the market start. 

B. SPP Interregional Issues

SPP is the neighbor of seven other entities with which there are significant cross border transactions: 

Associated Electric Cooperative Inc., Entergy, Midwest Independent Service Organization (MISO), 

Western Area Power Administration, Electric Reliability Council of Texas, Southwestern Power 

Administration, and Western Electricity Coordinating Council. Seams occur at the borders of 

entities’ footprints where regional operational and structural differences cause a discrepancy in 

prices, cost allocations, and response characteristics to constrained elements. Several activities are 

underway to identify and address these differences. There are direct discussions between the RTO 

operations groups, a taskforce established at SPP to look into these concerns, and the SPP Seams 

Steering Committee and a Seams Task Force have been formed by the Congestion Management 

Process Working Group (CMPWG). 

The CMPWG was established and conditionally accepted by the FERC to operate under a Joint 

Operating Agreement (JOA) between MISO and PJM, to satisfy a compliance requirement to 

develop agreements on how to manage congestion at their system seams. The CMPWG has become 

the primary organization active in the development of consistent practices and congestion 

management strategies for Reciprocally Coordinated flowgates in the Eastern Interconnection. 

Consequently, the CMPWG is highly involved in activities to help members fairly and consistently 

allocate costs associated with jointly coordinated flowgates, as well as encouraging a regional 

perspective on transmission planning issues. 

Initial analysis of seams issues identified problematic issues requiring further study and resolution: 

• Improvement of market flow calculations 

• Improvement of coordinated planning 

• Comprehensive cost allocation methodology 

• Parallel flow visualization methodology 
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Improvement of Market Flow Calculations 

Over the past several years, SPP has observed substantial amounts of unattributed flows over several 

flowgates near the border with MISO. Studies indicated the unattributed flows were largely 

explained by differences in the methodologies used by MISO and SPP to calculate market flows. 

This untagged parallel flow has both reliability and equity implications. The untagged flow has 

accounted for as much as 40% of the total flowgate capacity on certain flowgates near the SPPMISO border; this is well over three times the normal. To address this problem, SPP, MISO and 

PJM developed a task force, which reports to the CMPWG, to review the situation and develop 

options for improvements in the market flow calculation methodology. Various solutions were 

proposed, and a set of recommendations were developed and will be presented for approval to the 

appropriate entities. Due to the significant financial and reliability implications of this problem, the 

MMU strongly encourages the affected parties to develop a prompt and equitable solution. 

Improvement of Coordinated Planning 

A perennial issue that arises across the Eastern Interconnection is development and cost allocation of 

transmission infrastructure that spans regional boundaries. SPP established some limited 

coordination of transmission infrastructure development through the Integrated Transmission 

Planning process, and participates in interregional organizations such as ISO/RTO Council and the 

Eastern Interconnection Planning Collaborative. Broader use of coordinated planning is necessary, 

and SPP is actively working to increase stakeholder support for this endeavor. SPP will participate in 

discussions in which modeling assumptions, coordinated solutions for problems, and cost allocation 

methodologies that are equitable for member organizations will be developed. 

Comprehensive Cost Allocation Methodology 

A comprehensive interregional cost allocation methodology is needed to ensure that costs associated 

with flowgate congestion and transmission development are appropriately borne by the affected 

parties. The SPP Seams Steering Committee developed cost allocation principles in 2010, and SPP 

has begun discussions with neighboring entities regarding incorporation of these principles into 

various seams agreements. 

Parallel Flow Visualization Methodology 

Consistency in market flow methodologies is imperative as the bulk electric system becomes more 

interconnected. The North American Energy Standards Board (NAESB) is developing a single 

prioritizing methodology with which to consolidate and replace different market flow methodologies 

maintained by various regions. Two options are currently under consideration by the NAESB: 

requiring tagging of all non-firm resources, and allocating flowgate capacity in a similar manner as 

the current Congestion Management Practice. SPP will work with the NAESB to ensure that an 

adequate and equitable methodology is developed and implemented. 
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Summary and Conclusions 

As part of an interconnected transmission system, SPP has the obligation to ensure that its interests 

are represented throughout the bulk electric system. It is entirely appropriate for SPP to work with its 

neighbors to develop policies and procedures that establish efficiency and equitable transactions 

across seams. SPP is participating in several initiatives that should encourage long-term efficiency 

throughout the interconnected regions. 
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C. Developments in Natural Gas Markets 

Shale Gas Development 

Over the past several years shale gas development in the United States has occurred at a fast pace 

and shows little sign of slowing. Development of shale gas formations is principally driven by 

advancements in horizontal drilling technologies and formation fracturing processes. Innovations in 

these areas have dramatically decreased the cost of exploring shale gas formations. Consequently, 

previously uneconomic formations are being developed for commercial use and production from 

these fields is increasing rapidly. 

Shale gas development is an important consideration for the SPP region. Numerous significant shale 

gas areas are either entirely or partially within the SPP area, including the Fayetteville, ExcelloMulky, Haynesville, Barnett, and Woodford shale zones. Further development of these resources 

should increase regional gas capacity while keeping prices stable as more capacity is available. 

Pipeline Construction 

Closely linked with shale gas expansion is development of gas transmission infrastructure. Several 

large gas pipelines have been constructed in the past few years, and more are under development. 

The recently constructed pipelines have linked regional gas markets in ways never before seen. 

Historically, there have been substantial price differentials between different regions of the country, 

as the total capacity to move gas between the regions was constrained. While the differential still 

exists, it has substantially decreased; in some cases, prices have almost equalized as gas can now be 

moved more freely between the regions. 

Conclusions and Concerns 

There has been a fundamental shift in the technological development of natural gas drilling in United 

States shale formations. Expansion of exploration into previously uneconomic shale plays, coupled 

with the dramatic decrease in the cost of drilling technologies, has resulted in a vast increase in the 

country’s capacity to produce natural gas. Total natural gas reserves have increased substantially 

and, due to new pipeline construction, the total transfer capacity of natural gas has also increased. 

Consequently, natural gas prices are expected to remain stable in the near-term. Low stable prices 

are a boon to electrical generators using this fuel source, and SPP can expect Market Participants to 

take advantage of these prices. 

The MMU wants to ensure that all modeling and cost estimates reflect the fundamental shift in 

assumptions surrounding natural gas production. The MMU reviewed changes in the natural gas 

market and has the following three questions and issues for consideration: 

• Are the low gas prices fully reflected and represented in the modeling programs used for 

SPP’s planning efforts and cost estimates? 
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• Are recently developed models using gas cost estimates that reflect the downward basis 

change in total cost? 

• Do the previously released economic models and estimates retain their feasibility given the 

substantial change in actual fuel costs? 

The MMU hopes that recognizing the fundamental shift in natural gas pricing and incorporating this 

into SPP’s models and estimates will produce more accurate, efficient, and effective models and 

estimates. 
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D. SPP Congestion Management Changes

Transmission Loading Relief (TLR)/Congestion Management Event (CME) Procedure 

Review 

To manage congestion SPP uses several relief mechanisms, principally the Transmission Loading 

Relief (TLR) and Congestion Management Event (CME) processes. In the past the TLR process was 

the sole method for ameliorating excessive flowgate loading. An SPP tariff requirement specified 

that the TLR process must be utilized even when no Interchange Distribution Calculator (IDC) 

curtailable schedules existed. The TLR process is best suited for instances when there are IDC 

curtailable schedules, so the requirement that the TLR process be used in the absence of IDC 

curtailable schedules was not particularly helpful. Because the vast majority of TLR events had no 

associated IDC curtailable schedules, it became necessary to develop a secondary mechanism to 

more efficiently manage flowgate congestion. 

The secondary mechanism for better managing congestion is the Congestion Management Event 

procedure, which was implemented in August 2010. The CME procedure is utilized when the 

Market Operation System (MOS) activates a flowgate without automatically using the TLR process. 

This may or may not cause the MOS to re-dispatch around the activated flowgate; whether this 

occurs is largely dependent on the overall system configuration and loading conditions in the given 

interval. It is no longer necessary to use the TLR process when there are no associated IDC 

curtailable schedules; this is principally the case when a flowgate is affected by only market 

resources and schedules. However, if there are IDC curtailable schedules, the TLR process must still 

be utilized. 

The CME procedure has some additional benefits. It eliminates overlapping work by allowing SPP 

Reliability Coordinators to use the TLR process only when it is needed. The CME procedure reduces 

the total incidence of TLR reporting, providing a better basis of comparison with neighboring 

entities. The CME procedure, which has a faster response time than the TLR process, should result 

in faster mitigation of congestion management. 

Early Results of CME Implementation 

The following figure summarizes congestion statistics for 2009 and 2010, highlighting changes 

before and after the CME procedure implementation. The CME procedure resulted in a decline of 

over 4,000 total TLR hours. This is a substantial decrease, and indicates how extensively the TLR 

process was over reporting congestion in past years. The displacement of the TLR process by the 

CME procedure represents an improvement in the congestion management process for the SPP 

market system. 

 
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Figure IV.1 Changes in Congestion Management 

External External

Flowgates Flowgates 

Total CME Hrs. 0 0 0 4234 0 4234

TLR Hrs. Level 3 17039 983 18022 11948 1325 13273

TLR Hrs. Level 4 4107 95 4202 281 222 503

TLR Hrs. Level 5 790 103 893 632 438 1070

Binding RTB hrs. 1851 19 1870 1625 108 1733

Breached RTB hrs 90 21 111 83 32 115

2009 2010

SPP 

Flowgates 

Total SPP 

Flowgates 

Total 
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2010 Conclusions and Recommendations

SPP Market Performance 

The SPP wholesale electric market continues to be competitive, and overall market participation is at 

very high levels. Generation from resources that use Self-Dispatched status (self-scheduled) 

continues to decline and is now at about 1-2% of total generation. This is a dramatic change from the 

15-18% levels experienced in 2007, the first year of the market. High levels of generation in 

available status improve efficiency and support congestion management efforts. Other indicators of a 

strong market include relatively low levels of ramp rate deficiency intervals and declining levels of 

revenue neutrality uplift. One area of concern is the decline in dispatchable rage offered by Market 

Participants. 

Prices in the SPP region are well in line with expectations. Average prices are up slightly more than 

14%, which closely corresponds with the change in the cost of natural gas. There continues to be a 

very strong link between the cost of natural gas and the marginal cost of energy. This trend is likely 

to continue and the correlation may become stronger should natural gas continue to supplant coal as 

the marginal fuel. 

SPP prices are comparable to what is seen in other markets in neighboring regions. SPP prices are 

similar to those in MISO and less than those in ERCOT. The price differences between the markets 

are expected given the types of resources in each market and their relative fuel costs. This 

relationship is also true for price volatility. SPP volatility is slightly less than MISO and about half 

of what is experienced in ERCOT. 

Competitive Market 

The MMU considers the SPP EIS market to be workably competitive. Traditional market power 

assessments such as the Herfindahl-Hirschman index, a commonly accepted measure of market 

concentration, shows the SPP market to be un-concentrated. This is true when evaluating all capacity 

as well as the uncommitted capacity on the system. This assessment only reflects conditions when 

there is no congestion in the market footprint. Congestion will create conditions where there will be 

very high levels of concentration and limited competition. 

Because congestion creates conditions where individual market participants may have market power, 

SPP is required to have mitigation measures in the form of offer caps to deter and minimize potential 

abuses of market power. A review of prices and offers shows that offer caps have very little impact 

on prices in the SPP market. This is one indication that offers are generally competitive. 

 
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Localized Congestion Concerns 

The SPP system contains some highly congested transmission corridors that result in significant, 

local price volatility. The average annual price for the system was $31.33 in 2010. While specific 

load serving entities, with variable constrained conditions, experienced average annual prices 

ranging from $35.18 to $25.45. This is also reflected in the price volatility for individual 

participants. The SPP system price volatility is only 50% whereas individual participants experience 

volatility as high as 113%. The volatility and price differential have wide ranging production 

efficiency implications and may dampen participation in the market. 

Two transmission corridors within the SPP footprint experienced very high levels of congestion in 

2010: the Kansas City area and the Texas Panhandle area. Congestion on several flowgates in the 

region north of Kansas City is the primary driver for low prices and high volatility experienced by 

the Nebraska market participants. Several transmission projects have been developed to help 

alleviate this congestion. These projects have an in-service date of mid-2014. 

The Texas Panhandle transmission corridor has been the most congested area since the start of the 

EIS market. The limited import capability from SPP and via direct current ties into the SPS region, 

establishes a situation where local higher cost generation must be utilized in lieu of lower cost 

imports. Recent generation additions in this area have helped alleviate pricing differences but the 

problem is likely to persist until significant transmission capacity is constructed. Transmission 

development scheduled to be in service in 2014 should help reduce this congestion. 

Seams Issues 

RTO’s with different market rules and business practices may encounter difficulty in managing 

congestion, and in establishing effective and efficient operations at their borders (seams). The 

different rules and practices may result in price distortions and inefficient cost allocation between 

entities at the seams. These seams issues can become especially pronounced at highly congested 

transmission corridors. This is the case with the Kansas City area where SPP and MISO share a 

common border. 

SPP, MISO, and a number of entities that are directly impact by the congestion in the Kansas City 

area have been diligently identifying seams-related concerns and are developing mechanisms to 

address these issues. The RTO’s have established a number of task forces and working groups to 

enhance communication and reach equitable solutions for all involved. Given the levels of 

congestion in the affected area, and the potential for significant financial implications, it is important 

that the involved RTO’s resolve these issues as swiftly as possible. 

 
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Integrated Marketplace Design 

The SPP Market Working Group and the SPP Market Design team established a goal of developing 

an Integrated Marketplace design that incorporated the best components from existing markets. A 

comprehensive review of the Marketplace protocols by the MMU shows that these groups have been 

successful in accomplishing their goal. The proposed market protocols create a sound base for 

moving forward with the development of the Integrated Market Place. 
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Definitions of Select Terms 

Alternating Current - the movement of electric charge that periodically reverses direction 

Balancing Authority- The responsible entity that integrates resource plans, maintains loadinterchange-generation balance, and supports Interconnection frequency 

British thermal unit - amount of heat required to raise the temperature of 1 pound of water by 1 

degree Fahrenheit 

Congestion Management Event - process by which the market recognizes flowgate limits and 

dispatches resources accordingly, used chiefly when no curtailable transactions in the IDC are 

present 

Direct Current - the movement of unidirectional electric charge 

Energy Imbalance Service - the real time balancing between scheduled generation and load 

Energy Imbalance Service Market - the overall market structure surrounding the provision of EIS 

Flowgate - A designated point on the transmission system which serves as a monitoring point for 

energy flows, and through which the interchange distribution calculator calculates the power flow 

interchange transactions 

Generator to Load Distribution Factor - a numerical representation of the relative impact a 

generator has on a flowgate. If a GLDF is .1, for any 100MW change in output there is a 

corresponding effect on the flowgate of 10MW 

Giga-Watt hour - 1 thousand MWH or A measure of electrical energy equal to an accumulation of 

1,000,000,000 watts in a one hour period 

Independent System Operator - Responsible for coordinating, monitoring and controlling the 

operation of the electric system within its territory 

Kilovolt – 1,000volts 

Loacational Imbalance Price - The point specific price that results from the market operations 

system 

MM (mm) - Equivalent Roman numeral representation of one thousand thousand, or 1,000,000 

Market Operating System - The SPP system that creates Locational Imbalance Price (LIP) and 

deployment instructions for participating resources 

Market Participant - As defined in the SPP Tariff 

Mega-watt - an instantaneous measure of electrical energy equal to 1,000,000 Watts 

Mega-watt hour - A measure of electrical energy equal to an accumulation of 1,000,000 watts in a 

one hour period 

Open Access Transmission Tariff - SPP’s transmission tariff as posted on SPP’s website 

Revenue Neutrality Uplift - Process used to ensure that SPP remains revenue neutral in every 

market interval by either adding a surcharge or distributing money back to participants 

Regional Transmission Organization - Organization responsible for moving electricity over large 

areas, commonly at higher voltages and over larger areas than covered by an ISO 

Transmission Loading Relief - A process used to reduce loading on lines which are at risk for an 

overload 
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Common Acronyms 

Acronym Term 

AC Alternating current 

AECC Arkansas Electric Cooperative Corporation 

AECI Associated Electric Cooperative Inc. 

AEPW American Electric Power 

AFC Annual Fixed Cost 

BA Balancing Authority 

BTU British thermal unit 

CLEC Cleco Power LLC 

CME Congestion management event 

CT Combustion Turbine 

DC Direct Current 

DISIS Definitive Interconnection System Impact Study 

DOE Department of Energy 

EHV Extra High Voltage 

EIA Energy Information Administration 

EIS Energy Imbalance Service 

EMDE Empire District Electric Co. 

ENTR Entergy, Incorporated 

ERCOT Electric Reliability Council of Texas 

FERC Federal Energy Regulatory Commission 

GLDF Generator to Load Distribution Factor 

GRDA Grand River Dam Authority 

GWH Giga-Watt hour 

HHI Herfindahl-Hirschman Index 

IA Interconnection Agreement 

INDN City Power & Light, Independence, Missouri 

IOU Investor-Owned Utility 

IPP Independent Power Producer 

ISO Independent System Operator 

KACY Board of Public Utilities, Kansas City, Kansas 

KCPL Kansas City Power & Light 

GMOC Greater Missouri Operations Company 

kV Kilovolt (1,000 volts) 

LAFA City of Lafayette, Louisiana 

LEPA Louisiana Energy & Power Authority 

LES Lincoln Electric System 

LIP Locational Imbalance Price 

LNG Liquefied Natural Gas 
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Continued from previous 

(Acronym Term) 

MIDW Midwest Energy, Inc. 

MISO Midwest Independent Transmission System Operator 

MKEC Mid-Kansas Electric Company 

MM Thousand thousand 

MMBtu Thousand Thousand British Thermal Units (1,000,000 Btu) 

MMU Market Monitoring Unit 

MOS Market Operating System 

MP Market Participant 

MPS Missouri Public Service 

MRO Midwest Reliability Organization 

MW Megawatt (1,000,000 watts) 

MWh Megawatt Hour 

NERC North American Electric Reliability Corporation 

NPPD Nebraska Public Power District 

O&M Operation and Maintenance 

OASIS Open Access Same-time Information System 

OATT Open Access Transmission Tariff 

O/S Over-Scheduling 

OKGE Oklahoma Gas & Electric 

OMPA Oklahoma Municipal Power Authority 

OPPD Omaha Public Power District 

PISIS Preliminary Interconnection System Impact Study 

RE Regional Entity 

RNU Revenue Neutrality Uplift 

RTO Regional Transmission Organization 

SERC SERC Reliability Corporation 

SMP System Marginal Price 

SPP Southwest Power Pool, Inc. 

SPS Southwestern Public Service Company 

SECI Sunflower Electric Power Corporation 

SWPA Southwestern Power Administration 

TLR Transmission Loading Relief 

TRE Texas Regional Entity 

UD Uninstructed Deviation 

U/S Under-Scheduling 

VRL Violation Relaxation Limit 

WAPA Western Area Power Administration 

WECC Western Electricity Coordinating Council 

WERE Westar Energy, Incorporated 

WFEC Western Farmers Electric Cooperative