# 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 ............................................................................................................................ 1 4

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 ..................................................................................................................... 25Southwest Power Pool, Inc.

SPP 2010 State of the Market Report 2 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

.............................................................................................................................. .. 54Southwest Power Pool, Inc.

SPP 2010 State of the Market Report 3 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 ..........................................................................................................87Southwest Power Pool, Inc.

SPP 2010 State of the Market Report 4 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 C oordinated 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)/Congesti on Management Event (CME) Procedure Review ........ 97
Early Results of CME Implementation .................................................................................................. 97

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

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

Common Acronyms

.............................................................................................................................. .......103Southwest Power Pool, Inc.

SPP 2010 State of the Market Report 5 

## 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 El ectric Energy Demand for the SPP Market Region (MW) .......................20

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

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

Figure I.7 Daily Minimum and Maxi mum 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 Syst em Elements in the SPP Region ...................................................30

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

Figure II.1 Electricity Sales in th e 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 Ho urly 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 (90 th percentile) ................................37

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

Figure II.9 Average Annual Pri ce 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 be yond Threshold Levels for 2010 ..............................................................43

Figure II.14 Percent of Re-priced Hours by Month from 2008 – 2010 ...................................................44Southwest Power Pool, Inc.

SPP 2010 State of the Market Report 6 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 Result s 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 I ndex (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 Neut rality Uplift 2007-2010 .......67

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

Figure III.2 Annual SPP Transm ission Service Requests ........................................................................70

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

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

Figure III.5 Percent of Five-minute Interval s 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 .....................................................................................78Southwest Power Pool, Inc.

SPP 2010 State of the Market Report 7 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 Transmissi on 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 Out age 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 ....................................................................................98Southwest Power Pool, Inc.

SPP 2010 State of the Market Report 8 

## 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 he rein. SPP shall have no liability to recipients of this information or third parties for the consequen ces arising from errors or discrepancies in this information, for recipients’ or thir d parties’ reliance upon such inform ation, or for any claim, loss or damage of any kind or nature what soever arising out of or in conn ection with (i) the deficiency or inadequacy of this information for any purpose, wh ether or not known or disclosed to the authors, (ii) any error or discrepancy in this information, (i ii) the use of this information, or (iv) any loss of business or other consequential loss or damage whether or not resu lting from any of the foregoing.Southwest Power Pool, Inc.

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), a nd 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 r ecord 45,373 MW, an increase of approximately 14% from 2009. This substantial in crease 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 se t new records for demand. The principal driver of this increase was pervasive hot weather in most of the SPP re gion 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 fro m 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 reliabi lity and for mitigation of the potential exercise of market power within SPP.Southwest Power Pool, Inc.

SPP 2010 State of the Market Report 10 

### Generation Interconnection

As of the end of 2010, SPP had 140 active genera tion interconnection requests representing 25,892MW of potential genera tion under study. The vast majori ty 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 faciliti es experience outages when they are unavailable for use by the SPP system. Maintenance outages occur when a facil ity is scheduled to be out of service; these outages are typically coordinated with SPP. For ced outages occur when an unforeseen situation requires the facility to be removed from service.

In 2010, generation outages followed the expected tr end 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 substa ntially fewer transmissi on outages during summer compared to the shoulder months.



### C. EIS Market Results

Market Activity

In an imbalance market, a Market Participant ma kes a sale when (a) it generates more than it scheduled and/or (b) its actual load is less than it scheduled. Si milarly, 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 ch anges 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 lo ads. This report include s two separate views of prices: price comparisons with neighboring regi ons and price comparisons among SPP EIS Market Participants.

SPP prices are consistent compared to system pri ces from the Electric Reliability Council of Texas (ERCOT), and the Midwest Independent System Op erator (MISO). SPP’s year ly average price of $31.36 is slightly lower than MISO’s $31.86, a nd well below ERCOT’s $35.49. Price equalizationSouthwest Power Pool, Inc.

SPP 2010 State of the Market Report 11 between these regions is not realistic, but relative pr ices are similar to each ot her, indicating the three regional markets are yielding comparable results.

The second views of EIS Market pr ices assess price differentials between SPP Market Participants. While the SPP regional price was $31.36, average Mark et Participant prices ranged from a low of $25.45 to a high of $35.18. These price differences re flect 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 cap acity. In areas where si gnificant differentials exist, additional development woul d help create parity by encouragi ng the total transf er of energy, yielding efficiency gains.



### Revenue Adequacy (Cost R ecovery 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 gene rator would have been profitabl e 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 vi tal to understanding the EIS Market’s existing generating capacity and pricing st ructure. Moreover, by analyzing the fuel structure, conclusions can be drawn regarding the impact of proposed en vironmental 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 footpr int, 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 abou t 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 m ove to meet changes in total system demand. Natural gas was on the margin 62% of the time, indi cating that coal units we re at maximum and that gas generation was required to serve changes in sy stem load. Using the above data, system pricesSouthwest Power Pool, Inc.

SPP 2010 State of the Market Report 12 should reflect marginal costs from coal and natural gas generators in roughl y the same proportions as indicated by their marginal time.

The fuel type metrics also provide a review of wind generation in the EI S Market. In 2010 there were approximately 4,000 MW of wind capacit y, 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 participat es 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 interc onnected nature. Common me trics that describe market participation include analysis of dispatchable range, ramp rates, and status type use. Results of this type of analysis ma y indicate problems with market design, appropriate price signals, educational opportunities, or the n eed for operational improvements.

Dispatchable Range - The area between minimum and maxi mum 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 insuffi ciencies 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 disp atchable range contracts, its ability to respond to changing conditions diminish es. The MMU encourages all parties to analyze this issue and determine if the dispatchable range of Market Participants’ res ources can be increased.

Ramp Rate – The ramp rate is the amount a generato r 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 pe r-minute ramp rate was 276 MW, an increase of
14% from 2009. This increase is an encouraging result; however ther e 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 fo r market dispatch offer the most flexibility by allowing dispatch capabi lity and setting the market clearing price. In 2010,
resources available for market di spatch accounted for 77% of all ge neration, 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. Genera tion from nuclear faciliti es, while technically available, has virtually no dispatch capacity and is treated as a subset of “a vailable” status. Nuclear generation in 2010 was 9% of the total, up from 8% in 2009 and 5% in 2008.Southwest Power Pool, Inc.

SPP 2010 State of the Market Report 13 

### Market Power Mitigation

SPP is required by its Tariff provisions to have two offer capping program s. The SPP offer cap program screens Market Participan ts’ price offers based on their re spective congest ion 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 genera tion 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 dispatch ed near this cap .0046%
of the time.



### Market Power Monitoring

The SPP MMU has been expressly charged with m onitoring for instances of market power and developing various screens and tool s that aid in the identification of potential market power abuses.
A common measure of relative mark et power is the Herfindahl-Hirsc hman Index (HHI). The HHI is the sum of the squares of market shares for all EIS Market Particip ants, and shows relative
concentration within the market. The traditio nal threshold values of the HHI are:

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

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

• >1800 (traditional markets) >2500(electric ma rkets): 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 yi eld 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 “up lift”, because the amount of the adde r 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 rangi ng 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 av erage system energy cost demonstrates the net effect of system uplif t. 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 i ssue at this time.Southwest Power Pool, Inc.

SPP 2010 State of the Market Report 14 

### D. Energy Delivery

Transmission systems are pathways that link gene rators to load centers. There is substantial variability among these pathways both within an individual re gion 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 comp anies who own transmission assets. Members are entitled to revenues from this granted transmi ssion service. In 2010, total transmission owner revenue was approximately $628 million, an increas e of approximately 30% from $486 million in

2009.



### Transmission Service Requests

Entities in the SPP footprint that wa nt 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 serv ice 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 approve d by SPP. The number of approved requests fell steadily thro ughout 2010, which is a concern. This decline may be the result of changes in loading, congestion patterns, or better transmission utiliz ation. SPP needs to analyze the
conditions that caused this trend.



### Transmission Congestion

Transmission congestion causes prices to diverge as less economical units are us ed to balance supply and demand while maintaining reliability. The most common way to maintain system reliability is by using monitored elements called “flowgates”, wh ich represent flow points. Operators can achieve system control and stability by monitoring and controlling flow over flowgates.

Flowgate congestion - the num ber of intervals in whic h a flowgate was at or exceeded its limit - was 69% in 2010, down slightly from 71% in 2009. This le vel of congestion is not necessarily a concern, as congestion in the form of binding flowgates can indicate that the transm ission system is being fully utilized. However, breached flowgates or t hose that have exceeded their limit are problematic. In 2010, approximately 5% of all dispatch inte rvals included a breached flowgate. Breached flowgates lead to significant price differentials across the region and can a dversely impact individual market participants. High levels of price vola tility from breached flowgates can discourage participation in the market and there by 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 orSouthwest Power Pool, Inc.

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. Th ere were more than 26000 transmission outage days in 2010. A transmission outage day is equal to one outage da y 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. Th e 2010 STEP determines needed transmission investments for the ten-year period from Ja nuary 1, 2011 through December 31, 2021. Transmission expansion projects total more than $5.1 billion dollars. Proj ects include: 3,295 miles of new transmission lines, 947 miles of reconductored tr ansmission lines, 753Mvar of new capacitors, and over 100 new or upgraded transformers. The vast ma jority 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 co mpetitiveness, localized congestion, seams issues, and the Integrated Marketplace design.Southwest Power Pool, Inc.

SPP 2010 State of the Market Report 16 

## I. Overview of SPP Footprint

To ensure a consistent methodol ogy and enhance future reporting, and unless otherwise expressly stated, metrics in this report have been formulated using only the Market Part icipant footprint. This enhances the report’s consistency and provides a firm foundation for analysis. Because this is a substantial change from previous years, a dire ct 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 supp lies, adequate transmission infrastructure, and competitive wholesale electrici ty 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 plan ning, training, and market operations. Market operations and 2010 Energy Imbalance Service Market (EIS) results are discu ssed in this report.

In 2007 SPP launched its real-time EIS Market, compri sed of participants th at agreed to operate under the SPP Tariff, and Market Protocols. Th e market does not include all SPP members, only those that have agreed to the above terms and provisions. The Mark et Participant’s respective areas collectively form the EIS Market footprint. Unless ot herwise stated, the EIS Ma rket 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 Tr ansmission Congestion Rights, (b) a Reliability Unit Commitment process, (c) a Real-Time Balanc ing Market, similar to today’s EIS Market, and (d) a price-based Operating Reserves procuremen t. 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 por tion of the Eastern Inte rconnection. It is bordered by the Midwest Reliability Organization (MRO) and the SERC Relia bility Corporation (S ERC) in the Eastern
Interconnection. SPP also shares borders with the Western Electricity Coordinating Council (WECC) and the Texas Regional Entity (TRE). Fi gure I.1 shows the four NERC Interconnections and the eight Regional Entities in North America.

Figure I.1 NERC Interconnections

Source: NERC.comSouthwest 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 utilit ies, independent power producers, and power
marketers. For a list of all SPP member s, 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 61Southwest Power Pool, Inc.

SPP 2010 State of the Market Report 19 

### SPP Balancing Authorities

The SPP market footprint is compri sed of 15 Balancing Authorities, which are operated by investorowned utilities, cooperatives, municipals, and stat e 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 Ba lancing Authorities is shown in Figure I.3.

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

SPP 2010 State of the Market Report 20 

### B. Electricity Dema nd in the SPP Region

The SPP EIS Market is comprised of Market Partic ipants who have individual load and resource profiles, but are all commonly serv ed by SPP. A standard way to compare load changes across time is to review peak system demand statistics by ye ar. Figure I.4 depicts mont hly 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 ar e 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 particul ar year or season may represen t 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 de mand. 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 Elec tric 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 31,072Southwest Power Pool, Inc.

SPP 2010 State of the Market Report 21 

### Market Participant Peak and Total Demand

Figure I.5 depicts 2010 total load, th e 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 prim arily comprised of legacy vertically integrated utilities, which tend to be quite large. Many Market Participants experienced significant, and in some cases record peaks, within thei r 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 Dema nd 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 y ears. 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 co ld 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 primaril y driven by the addition of new ma rket participants in Nebraska. Population growth in the SPP region has been subs tantial, 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 18,465,814Southwest Power Pool, Inc.

SPP 2010 State of the Market Report 23 

### System Demand Profile

Figure I.7 depicts total minimu m and maximum hourly demand for 2008-2010. There is a significant upward trend in both minimum and maximum hourly peak values, and a subs tantial 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 mini mum and maximum values is over 18,000 MW; the EIS Market had to adjust th e 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 genera tion 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 handli ng in the short-term, whic h would result in a ramp constraint condition. Ramp constraine d conditions indicate where market inefficiencies are likely to occur and highlight areas where enhancing mark et parameters would be most useful.

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

0 5000 10000 15000 20000 25000 30000 35000 40000 45000 500001‐Jan‐081‐Feb‐081‐Mar‐081‐Apr‐081‐May‐081‐Jun‐081‐Jul‐081‐Aug‐081‐Sep‐081‐Oct‐081‐Nov‐081‐Dec‐081‐Jan‐091‐Feb‐091‐Mar‐091‐Apr‐091‐May‐091‐Jun‐091‐Jul‐091‐Aug‐091‐Sep‐091‐Oct‐091‐Nov‐091‐Dec‐091‐Jan‐101‐Feb‐101‐Mar‐101‐Apr‐101‐May‐101‐Jun‐101‐Jul‐101‐Aug‐101‐Sep‐101‐Oct‐101‐Nov‐101‐Dec‐10MW

Daily Minimum Daily Maximum SpreadSouthwest 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 tr aditional load curve, as shown above in Figure I.7, in which hourly load values ar e sorted by magnitude instead of chronologically. A load duration curve shows the relative magnitude and fr equency 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 percenta ges 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 ex tremes are higher than the previous year, shortterm loading events are likely the reason. However, if the entire load cu rve is higher than the previous year, it indicates that to tal system demand has increased, which is the case as shown below. There is a distinct bend in 2010’s upper load valu es, 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 8001Load(MW) 2008

2009

2010 2% of hours

5% of hours

10% of hours

26% of hours

45% of hours

14% of hoursSouthwest 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 dema nd from the commercial a nd industrial sectors. Load growth patterns are an important considera tion in the RTO’s modeling efforts, and the MMU encourages SPP to fully quantify the expected growth pattern thr oughout 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 Aut horities and corresponding sum of their installed generating capacity as of December 31, 2010. Tota l generating capacity in the SPP EIS Market region was 65,524 MW, a 4% increase over 2009’s total generation capac ity. 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 64787Southwest Power Pool, Inc.

SPP 2010 State of the Market Report 27 

### Resource Margin

As depicted in Figure 1.10, SPP has a significant resource ma rgin. The region’s total annual generating capacity compared to peak demand re sults in the SPP resource margin: the amount of extra system capacity available af ter peak load has been serve d. 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 t ype 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 natu ral 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 im plied heat rate shows the relative efficiency required of a generator to convert gas to electr icity and break even, given system prices.

Figure I.12 shows the Implied Heat Rate for th e years 2007-2010. The implied heat rate shows significant spikes during some months which are la rgely coincident with pe ak loading events or significant transmission congestion issues. When the im plied heat rate increases , the relative value of additional efficient generation also increases. Genera tion that otherwise would not have been needed was required to meet system demand, a nd prices increased accordingly.

Figure I.12 Implied Heat Rate

5 6 7 8 9 10 11 12ImpliedHeatRate(MMBtu/MWh)Southwest Power Pool, Inc.

SPP 2010 State of the Market Report 29 

### Summary and Conclusions

There is little cause to be c oncerned 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 su fficient generation capacity in the region for the foreseeable future. This does not mean capacity additions at select loca tions 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 an d managing interfaces with neighboring regions, excess capacity may be utilized in th e form of power sales to external entities.

The continued development of wind resources may have unanticipated cons equences if the power flows become overly unpredictable. It is essentia l 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. Furthe rmore, a determination on the construction cost allocation of transmission infrastructure necessary to support wind generation wi ll be critical to the continued development of renewable resources.Southwest Power Pool, Inc.

SPP 2010 State of the Market Report 30 

### D. Transmission – The Brid ge 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 regi on use differing voltage le vels as the backbone of their respective systems. 345 kV is the predom inant 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 Syst em Elements in the SPP Region

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

SPP 2010 State of the Market Report 31 

### Inter-grid Connection Points

In addition to the alterna ting current grid referenced above, ther e are seven direct current (DC) ties
with other interconnectio ns. These DC ties serve as interc onnection points to other grids by converting power through AC-DC-AC interfaces. A unique characteristic of this type of interface is its controllability and stabilit y. Energy transfers are known, easily identifiable, and very tightly
controlled. A list of the seven DC ti es is provided in Figure I.14.

Two of the DC ties connect the SPP region with th e 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, Blackwa ter, 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 larg ely 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 fo r macro transfers across the region. SPP has been working with and coordinating transmission development throughout the region to increase the system’s overall reliability, e fficiency, and effectiveness. DC Tie Name Transmission Capacity (MW)

ERCOT East 600

ERCOT North 210

Lamar 210 Eddy County 200
Blackwater 200 Sidney 200 Stegall 200Southwest 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 govern ing 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 refere nce 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 depi ct 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% decrea se 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 in formation is that the to tal magnitude of dollars for purchases and sales is driven by gas costs in th e SPP region. As the price of gas changes, the total energy cost changes, as does the EIS portion of to tal 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 th e 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 201 0Southwest 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 ar e yielding similar results. It is not realistic to ex pect prices to be identical across the regions, as market structur es vary and resource fuel mixes are markedly different. For this review, SPP pr ices are compared to prices in the Midwest Independent Transmission System Operator (MISO) and the El ectric Reliability Counc il of Texas (ERCOT), the
two electric wholesale mark ets adjacent to SPP.

Figure II.3 shows 2010 system average prices for th e SPP, ERCOT and MISO re gions. Prices in the SPP region are slightly less than prices in MISO, a nd 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 somewh at 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 opera te than either coal or nuclear generators; consequently, system prices tend to be higher in regions with hi gh gas generator c oncentration. 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 represen ts the average volatilit y. The volatility is calculated by dividing the standard deviation of hourly regional pr ices 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 dist ribution curve. If volatility is low, prices tend to be dispersed away from the system average, or n ear the mean of the price distribution curve.

Figure II.4 shows 2008-2010 average pr ices for SPP, MISO, and ERCO T. Average prices for all three regions were slightly hi gher in 2010 than in 2009. Average pr ices 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. Ot her 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 pr ices 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 intere sting measure of regional differences is the magnitude of difference between Off-Peak prices for the regions. This diffe rence reflects the comp osition of the regional resource fleets. Coal generati on capacity comprises a large pe rcentage 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 genera tors are likely the marginal res ource, which yields lower system prices.

Figure II.4 Regional Electricity Price Characteri stics for 2010

Figure II.5 depicts 2008- 2010 prices in the SPP, MI SO, and ERCOT regions. SPP prices tend to be between MISO and ERCOT prices, largely due to different regional resour ce 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 Ho urly Average Prices for 2008 – 2010 

### Region 2008 2009 2010 2 008 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 $120Jan‐08Feb‐08Mar‐08Apr‐08May‐08Jun‐08Jul‐08Aug‐08Sep‐08Oct‐08Nov‐08Dec‐08Jan‐09Feb‐09Mar‐09Apr‐09May‐09Jun‐09Jul‐09Aug‐09Sep‐09Oct‐09Nov‐09Dec‐09Jan‐10Feb‐10Mar‐10Apr‐10May‐10Jun‐10Jul‐10Aug‐10Sep‐10Oct‐10Nov‐10Dec‐10$/MWh

SPP MISO ERCOTSouthwest Power Pool, Inc.

SPP 2010 State of the Market Report 36 

### SPP and Gas Price Comparison

Figure II.6 compares the average Panhandle hub ga s price and the SPP mont hly 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 mo st often gas units. There was a general increase in gas prices, approxima tely 25% from 2009 to 2010. However, even with this increase, average gas prices are we ll 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 discusse d 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 li kely also remain quite stable.

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

0 2 4 6 8 10 12

$0 $10 $20 $30 $40 $50 $60 $70 $80 $90 $100Jan‐08Feb‐08Mar‐08Apr‐08May‐08Jun‐08Jul‐08Aug‐08Sep‐08Oct‐08Nov‐08Dec‐08Jan‐09Feb‐09Mar‐09Apr‐09May‐09Jun‐09Jul‐09Aug‐09Sep‐09Oct‐09Nov‐09Dec‐09Jan‐10Feb‐10Mar‐10Apr‐10May‐10Jun‐10Jul‐10Aug‐10Sep‐10Oct‐10Nov‐10Dec‐10GasPrices($/MMBtu)EnergyPrices($/MWh)

SPP Average On

‐ peak Panhandle Gas PricesSouthwest Power Pool, Inc.

SPP 2010 State of the Market Report 37 

### Average Hourly Prices

Figure II.7 shows the hourly price ra nges of SPP, MISO, and ERCOT for t hose prices that fall within
two standard deviations of the mean. Prices that fa ll outside of two standard deviations are excluded, both on the high and low sides. This was done to better illustrate the normal pr ices that occur in the listed regions. Had those prices outside of two st andard deviations been included, the ranges in the table would be much greater and i ndicate that price extremes are mo re significant than their actual occurrence would signify.

Average hourly prices are largely equivalent acro ss the regions. ERCOT prices are the most volatile, as shown by the greatest maximum and minimum pri ces. 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 ma rket operations, as congestion costs and other pricing fa ctors should naturally result in price extremes greater than the mean. Pricing extremes do occur below th e mean, although with less frequency.

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

‐ 40 ‐ 20

0 20 40 60 80 100 120 140

ERCOT MISO SPP$/MWh

Min Max AverageSouthwest 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 depi cts a price durati on curve similar
to the load duration curve in Fi gure I.7, except that sy stem hourly prices are used. Prices are substantially lower than in 2008 and slightly hi gher than 2009. This chart shows the incidence of price extremes in rela tion 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 2010Southwest Power Pool, Inc.

SPP 2010 State of the Market Report 39 

### Market Participant Price Comparisons

While pricing comparisons between SPP and its nei ghboring regions show the relative robustness of the regional markets, they do not assess individu al participants within the region. To better understand the intricacies of the SPP region, it is n ecessary to establish metrics that analyze SPP’s individual Market Participants. Th e remaining metrics in this section provide an analytic backbone
for the review of the SPP EIS Ma rket and its participants.

Figure II.9 shows annual 2008-2010 average prices fo r SPP’s EIS Market Participants. 2010 prices
are above those from 2009 but ar e substantially below 2008 levels . In 2010, the Golden Spread Electric Cooperative (GSEC) ar ea experienced the hi ghest average prices of $35.18, while the Lincoln Electric System (LES) area experienced th e lowest average prices of $25.45. Prices for these two participants represent the SPP region’s extremes, as they are si gnificantly 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 Pri ce 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 WRGSAveragePrice($/MWh)

Balancing Authority

2008 2009 2010 SPP System AveragesSouthwest 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 review ing price volatility. The volatility experienced by Market Participants indicates the relative stabil ity 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 indica tor of a major market problem; however, it indicates areas which are impacted the most by congestio n and extreme pricing events. High levels of volatility present several long run problems, they indi cate areas in which price stability is least likely to occur, and they may disc ourage 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 90 th percentile of hourly prices, meaning the prices outside of two standard deviations of the mean were excluded. Both pr ice volatility and the system average price have increased from 2009. Congestion is the principal driver for both volatil ity and price extremes, and as indicated in this figure, congestion and volatility affect cer tain participants to a larger extent than others. Average prices of zero indicate the Market Participant di d 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 50.00 100.00 150.00 200.00200820102009200820102009200820102009200820102009200820102009200820102009200820102009200820102009200820102009200820102009200820102009200820102009

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

Min Max AverageSouthwest Power Pool, Inc.

SPP 2010 State of the Market Report 42 

### Average Monthly Prices

Figure II.12 shows Market Par ticipants’ average monthly pr ice for 2008-2010. There was some significant deviation between Market Participants’ syst em prices. Differing pri ces are to be expected, as participants each have resource fleets and c ongested areas that behave differently. Differences between Market Participant prices in any given month likely indica te there was congestion in the affected region that caused this deviation. If cong estion had not been presen t, prices experienced by
all the Market Partic ipants would have been identical. Cons traints or congestion into or out of Market Participants’ areas cause price deviation a nd may lead to substantial differences in their average prices.

Average price separation between Market Particip ants 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 WRGSSouthwest Power Pool, Inc.

SPP 2010 State of the Market Report 43 

### Interval Price Excursions

Interval prices are the most gran ular of all SPP EIS Market prices . The Market Operations System generates prices for all pricing nodes every five mi nutes, once for each market interval. These prices represent the value of energy at a pa rticular 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 highe r 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 th e listed categories is de picted. Prices higher than $400 or less than $0 generally indicate a market limitation.

The $400/MWh price reflects the initial FERC bid cap th at was in place for the first three months of EIS Market operations in 2007. The FERC cap ha s 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 dist ribution falls well within expectati ons. Extreme pricing events denoted prices less than $0 or greater th an $400 are infrequent, occurring less than 1% of the time. These pricing extremes are largely driven by severe tr ansmission constraints or system ramp limitations, both of which are carefully monitored by the MMU.

Figure II.13 Interval Prices be yond 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 Op erations 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 substa ntial 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 ru nning 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%JanFebMarAprMayJunJulAugSepOctNovDecJanFebMarAprMayJunJulAugSepOctNovDecJanFebMarAprMayJunJulAugSepOctNovDec

2008 2009 2010PercentofHoursRepricedSouthwest Power Pool, Inc.

SPP 2010 State of the Market Report 45 

### 2010 Price Contour Map

A final look at prices is provi ded in Figure II.15, which depicts the 2010 price contour map. This figure is a visual depiction of the price differentia l that resulted from conges tion; it was calculated by average prices at each pricing node for the year.

There was significant, prolonged congestion at six di stinct locations. For a detailed list of the flowgates that correspond with th ese areas, refer to Figure II.16, Principal Congested Flowgates by
Area.

For the fourth year, the Texas panhandle is th e most congested area in the SPP region. There are several explanations for this, leading to a funda mental 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 deve lopment 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

O klahoma City Tulsa Texas Panhandle Wichita Area

SE Kansas Kansas City Area

SW Kansas

SE OklahomaSouthwest Power Pool, Inc.

SPP 2010 State of the Market Report 46 

### Principal Congested Flowgates

Congestion in the SPP system is largely concentrat ed 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 re gion. 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 fl owgates. Several flowgates may correspond with any given congested interface. Also included are proposed transmission solutions that would help in some way alleviate the c ongested element, as proposed by SPP Transmission Planning. Figure II.16 Principal Congested Flowgates by Area

Region Flowgate Name Flowgate Location (kV) A verage 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 Reliab ility)

1. Tuco Int. – Woodw ard 345 kV line (May 2014 - Balanced Portfolio) 2. Castro County Int. – New hart 115 kV line (April 2015 - Regional Reliab ility)

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 – Va lliant 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 - Spearv ille [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] $23.83Southwest Power Pool, Inc.

SPP 2010 State of the Market Report 47 

### Summary and Conclusions

During 2010, congestion in the SPP region followed si milar patterns as in 2009. Principal congested
corridors and their associated flow gates 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 eff ectiveness 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 Pa nhandle 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 con tinually 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 th e baseline selection mechanism which determines the investment cost of new generation. To reduce the co mplexity of the baseline selection process, the SPP MMU made several simplifying assumptions and relied extensively on th e Electricity Market Module published by the Energy Information Administration 1 . Key assumptions from the Electricity Market Module can be found in Figure II.17. For this an alysis, three technologies were selected that represent the most likely contributi on to new generation capacity in the SPP region: Scrubbed Coal, Advanced Gas Combined Cycl e, and Advanced Combustion Turbine.

Figure II.17 Key Assumptions in Revenue Adequacy Formulation

Determining the potential profitability of a new ge nerating facility involv es 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 estim ated 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 ye ar and the result is summed.

1 http://www.eia.doe.gov/oiaf/aeo/assum ption/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 8,550Southwest Power Pool, Inc.

SPP 2010 State of the Market Report 49 In Figure II.18 the actual return represents the pot ential revenue stream of a new generating facility using the above method. Comparing the actual return to the expect ed plant return determines if investment in a new generating f acility is warranted. The expected plant return uses an assumed return on equity of 10%.

For all fuel types, the actual retu rn that could be expected from i nvestment 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 de mands, 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 pri ce 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 conges tion and prices significan tly different than the system mean. However, in every case projected revenues do not warrant ne w construction. This situation is as expected given the very large rese rve margin in the SPP footprint shown in Section I.C
Generation.

Figure II.19 Revenue Adequacy Result s 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 ParticipantSouthwest 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 othe r 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 ma intain reliability during system emergencies.

Figure II.20 depicts 2010 generation in the SPP EIS Ma rket 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 t ype, which generated 22.61%. Traditionally, coal has been the largest source of energy in the SPP re gion, but recently gas generation has increased its total market share. Th ere are several reasons for this. As gas prices decline, the relative cost of generation from this fu el 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 gene ration 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 2010Southwest Power Pool, Inc.

SPP 2010 State of the Market Report 52 

### Generation on the Margin

Figure II.22 displays which fuels ar e at the margin in SPP, thus setting market prices. The system marginal price is calculated as the price of the next MW available after th e total system demand has been met. The Locational Imbalance Price (LIP) is the system marginal pr ice plus any congestion charges associated with the pricing node. For a ge nerator to set the system marginal price, the resource must: (a) be in “availabl e” status, (b) not at the resour ce plan minimum or maximum, and (c) not ramp limited.

As highlighted in Figure II.20, gene ration 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 leve ls, an interesting phenomen on may develop regarding marginal fuel ratios. As fuel costs change, particip ants review their resource fleets and determine the most economical long term mix. As the relative gas to coal cost declines, part icipants 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 fo r wind generation, and wind investment and development continues throughout. Figure II.23 depicts capaci ty and total generation
from wind facilities for December 2008-Decembe r 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 4,000Wind 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, a nd resource control parameters. Specifically, Market Participants may modify the control paramete rs of their resources by changing any or all of the following: dispatchable range, resource minimu ms, resource maximums, ramp rates, price offers, resource status, etc. The following charts and de scriptions depict some key components of these
parameters.



### Dispatchable Range

Dispatchable range is a control parameter that allo ws resources to alter their total range of operation.
If a unit has a 500 MW maximum and a 100 MW mini mum 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 dispatch able range by the amount of the se rvice. Limiting the dispatchable range or resources diminishes th e responsiveness of the EIS Mark et because it sh rinks 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 dispat chable range of available reso urces 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 dispatchab le 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 ra nge 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 EI S market operations because they place limits on how quickly a unit can respond to changes in loading conditions or dispat ch 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 mo re rapidly and adjust more quickly to these changes. Lower ramp rates increase the total respons e 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 tw o functions: they indicate that there is not enough ramp from available resources in a specific location, and they provi de incentives to Market Participants to provide sufficient ramp to maintain th e 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 interval s. The total available ra mp 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, b ecause 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 100MW Ramp Available per MinuteRamp Deficiency Intervals

UP Ramp Deficiency Intervals DOWN Ramp Deficiency Intervals Total MW Ramp Available per MinuteSouthwest 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 st andardized by available capacity, compared to the average online capacity. The total standardized sy stem ramp remained fairly constant across time, although there is a slight downward trend. Sufficient ramp is v ital to ensure proper market operation. There was speculation that as participants became more co mfortable with the market, they would increase participation by increasing their ramp rate and othe r control parameters. This does not appear to have happened. Because of the vital nature of sufficien t 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 1.4Average Online Capacity (GW) per IntervalMW / Minute / 100 MW of Online Capacity

Available Online Capacity MW / Min Offered / 100 MW of Online CapacitySouthwest Power Pool, Inc.

SPP 2010 State of the Market Report 57 

### Status Type Utilization

Another way a Market Participant can modify its resource control paramete rs is by selecting the status type listed in their resour ce plans. The status type indicate s the manner in which the resource
is allowed to function. There are fi ve status types: available, una vailable, self-scheduled, manual, and supplemental. Only the availabl e status type allows the market to fully utilize a resource by changing the resource output and allowing it to set th e 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 su m of schedules against
the resource. For a resource in self-scheduled st atus, a Market Particip ant has essentially predetermined an output level, regard less of overall market conditions or operations. Unavailable status
indicates the resource is offline and not availa ble for use by either the market or the Market Participant. Supplemental status i ndicates the resource is offline but available to come online within
ten minutes. Available status units are most usef ul to the market because they can respond to instructions and quickly resolve congestion a nd alleviate other operati onal constraints.



### Generation by Status Type

Figure II.27 shows generation from res ources 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). Intermitt ent resources are becoming more important in the EIS Market, and the status types we re separated to ensure proper categorization of generation from these resources. A point of interest is the stea dy decline in Self-Dispatc hed generation. The MMU has made a concerted effort to discourage the us e of Self-Dispatched stat us and is gratified to recognize the decline in the us e of this status.

Figure II.27 Generation by Status Type

- 5,000 10,000 15,000 20,000 25,000GWh Production

Other Manual (other) Manual (intermittent) Nuclear Self-Dispatch Market DispatchSouthwest 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 princi pal 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 exampl e of Economic Withholding.

The SPP Market Monitoring Unit is directly ch arged by FERC with mitigating instances of Economic Withholding. Consequently, the MMU ha s 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 fo llowing conditions: (a) congestion is present in the system, (b) resources are in a position to wield potential mark et power and their Generator to Load Distribution Factors are greater in magnitude than -5%, and (c) aff iliate resources of any capped resource are also capped. The SPP offer cap comes into play only during times of congestion. Without congestion, comp etition between Market Partic ipants 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 resource s at all times. Neither the FERC nor SPP offer caps are price caps. Prices are set th rough 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 ne ar the FERC cap is exceedingly small. On average a resource is dispatched near th e FERC cap .0046% of the time. Res ources 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 th e 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 th e imposition of the cap. Assuming this is the case, on average only .0203% of resource in tervals were impacted by the capping methodology. This is a very small percent of total time and indicates th at Market Participant offers are typically well w ithin acceptable limits.

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

Although the data developed in Fi gure II.28 clearly shows the offe r 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-inter vals 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 percenta ge of offer capped intervals. Th e metric in Figure II.29 considers
all resource-intervals for the denom inator, regardless of status, out age, 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 pi votal to an activated flowgate. The Security Constrained Economic Disp atch (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 do llars 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 presen t, EIS dollars paid to this resource are not affected. The methodology used in Figure II.28 indicate s that the SPP offer cap affected payments 137 times out of a million, whereas the methodology fro m 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 (M arket Participant Capacity)

The Herfindahl-Hirschman Index (HHI) is a comm on measure of competitiveness used to identify
relative levels of market concentr ation. The U.S. Department of Jus tice is a predominant user of the HHI as part of its approval process for merg ers 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 work ably competitive solution. A HHI over 1,800 is said to indicate a highly concentrated market, and is un likely to be competitive. In the case of electric markets, a higher level of 2500 is accep ted as an upper threshold level.

Figure II.30 shows the Herfindahl-Hirschman inde x for 2007-2010 calculated from total generation capacity shares. The HHI has declined as more Ma rket Participants have been added to the EIS Market footprint. HHI values at this level i ndicate 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 pow er concerns, but does indicate that an individual participant is unlikely to successfully manipulate th e system by withholding capacity.

Figure II.30 Herfindahl-Hirschman I ndex (Market Participant Capacity)



### Herfindahl-Hirschman Index (Uncommitted Capacity)

Figure II.31 shows the Herfindahl-Hirschm an index for the years 2007 through 2010 for uncommitted capacity by market participants. Unco mmitted capacity is calculated as the installed capacity at the summer peak minus the maximum lo ad 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 dow nward across time as more pa rticipants 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 IndexSouthwest 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 inde xes show competitive market conditions. There was a slight increase in the HHI values in 2008 as system reconfigurat ions occurred. However, in both 2009 and 2010, the HHI values have declined markedl y. This clearly shows th at during times of no congestion, that the market is workably competiti ve and that individual market participants are unlikely to be successful by withholding eith er 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 c ontrol of less than 20% of the total uncommitted capacity, then they pass this market power test.

The uncommitted capacity is the market capacity re maining 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 othe r 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 Shar es 2010, clearly highlights the limited impact
attributable to individual market participants. Moreover, as no indi vidual market participant passes
the 20% threshold of uncommitted ca pacity, 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 neutra l in its market operations processes. The total money paid to Market Participants for a given h our must equal the amount collected from Market Participants. Market operations ma y result in instances in which there is a difference between net values either paid or collected by SPP. Should this occur, SPP must either up lift the deficiency to all Market Participants or distribu te the over-collection back to Ma rket Participants by including an adder in the hourly settlement.

There are five components to Revenue Neutrality Up lift (RNU) (a) Energy Imbalance Service (EIS), (b) self-provided losses (SP loss), (c) over-schedu ling charges (O/S), (d) under-scheduling charges (U/S), and (e) uninstructed deviation (UD) charge s. Positive numerical re sults represent an overcollection by SPP and a payment to Market Partic ipants. Negative numerical results represent an under-collection by SPP and require a payment from Ma rket Participants. EIS results may be either positive or negative; SPP may either under or ove r 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 deviat ion charges are always levied against Market Participants, which means th ey 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 thenSouthwest 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 be tween 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 re presents 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 instrume nts being left in place that are greater than the flowgate’s simultaneous feasibility capability. If this o ccurs, 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$(inthousands)

EIS O/S U/S UDC SP LOSSSouthwest 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 29.54Southwest 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 reve nue 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 imbala nce is uplifted by market participant; positive uplift in a given hour may offset negative uplift from a different hour. To count eract this effect, the absolute RNU is shown in Figure II.35. As can be s een in the figure, the tota l 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 no ticeable decline in RNU since the start of the market and indicate an improvement in the efficien cy of the market. There is a long term downward
trend in Net EIS RNU. This indicat es more costs are being allocated to actions and entities that are causing the cost and an indicati on that the overall efficiency of the market is improving.

Figure II.35 Monthly Net vs. Absolute Energy Imbalance Revenue Neutrality Uplift 2007-2010Southwest Power Pool, Inc.

SPP 2010 State of the Market Report 68 

## III. Energy Delivery

A. Transmission Service

The SPP Regional Transmission Organi zation is obligated by FERC to manage and regulate the flow of energy across the transmission sy stem within its territory. SPP me mber companies have agreed to allow SPP to administer their component transmissi on systems and place these transmission facilities under provisions of the SPP Open Access Transmission Tariff. The Tariff contai ns 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, a nd Business Practices. Market Partic ipants work with SPP to ensure
the maximum amount of transmission service re quests are approved, while maintaining system reliability and security. Changes in demand patte rns 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 revenu e generated from use of the transmission system. Total 2010 revenue was a pproximately $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$(inMillions)

MonthSouthwest 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 desi re to use specific transmission system paths. The rate of confirmation of initial requests may repres ent the demand for access to the grid, and may also provide insight into the grid’s ability to simultaneously acco mmodate demand for transmission paths.

Figure III.2 depicts 115,000 transm ission service requests in 2010, a slight increase from 2009 but well below the long-term average. This number repres ents requests that were approved, modified or rejected.

Figure III.2 Annual SPP Transm ission 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 identif ied the following possibilities fo r the decline in transmission reservations: severe economic downturn, restruct uring 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 2010TotalRequestsSouthwest Power Pool, Inc.

SPP 2010 State of the Market Report 71 Any number of the above reasons may be contributi ng 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 trad ing entities, and the acceptance and reliance on market mechanisms that supplant the need for se parate scheduling schemes. Consequently, the MMU does not think that this poses any sort of st ructural manipulation or is in any way adversely affecting the transmission market.



### Transmission Service Requests by Status

A more nuanced view of transmission service request s 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 transmissi on service requests incr eased slightly in 2010 from relatively stable levels in 2009, following substantial declines in late 2007 and mid-2008. A large decline in to tal transmission service requests is no t worrisome in this case. The SPP EIS Market began operation in February 2007, and many Market Participants lik ely reduced their total requests as their comfort with market operations increased.

Figure III.3 Monthly SPP Transmission S ervice Requests by Status from 2007 – 2010

0 2000 4000 6000 8000 10000 12000 14000 16000 18000 20000TotalRequests

Approved Refused OtherSouthwest Power Pool, Inc.

SPP 2010 State of the Market Report 72 

### Approved and Refused Transm ission Service Requests

Modifying the above chart by removing the “Other” st atus generates Figure III.4, Monthly Approved and Refused Transmission Service Requests 2007–2010. The percentage of approved transmission service requests declined st eadily during 2010, largely due to the sharp increase in refused transmission requests. The increase in refused requests is largely attr ibutable to congestion. This is not necessarily a bad condition, because congestion re sulting from full utilization of the transmission system is a natural consequence of the current mark et 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 Tr ansmission Service Requests from 2007 – 2010

0% 10% 20% 30% 40% 50% 60% 70% 80% 90%

0 2000 4000 6000 8000 10000 12000 14000 16000Jan‐07Feb‐07Mar‐07Apr‐07May‐07Jun‐07Jul‐07Aug‐07Sep‐07Oct‐07Nov‐07Dec‐07Jan‐08Feb‐08Mar‐08Apr‐08May‐08Jun‐08Jul‐08Aug‐08Sep‐08Oct‐08Nov‐08Dec‐08Jan‐09Feb‐09Mar‐09Apr‐09May‐09Jun‐09Jul‐09Aug‐09Sep‐09Oct‐09Nov‐09Dec‐09Jan‐10Feb‐10Mar‐10Apr‐10May‐10Jun‐10Jul‐10Aug‐10Sep‐10Oct‐10Nov‐10Dec‐10

Approved Refused % ApprovedSouthwest Power Pool, Inc.

SPP 2010 State of the Market Report 73 

### B. Transmission Congestion

An important consideration in anal yzing overall market health is to study the use or overuse of the transmission system. In an ideal world, the transm ission 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 conge stion under certain conditions.

Flowgates are used to monitor the transmission sy stem 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 en ergy flows must be monitored and controlled. SPP manages total system flows over these flowga tes 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-pea k, 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 av erage of 71% of all inte rvals had at least one congested flowgate. Interestingl y, congestion tends to occur duri ng 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. th rough 7 a.m. - indicates that something other than traditional load patterns is driving congestion.

Figure III.5 Percent of Five-minute Interval s 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 2010Southwest Power Pool, Inc.

SPP 2010 State of the Market Report 75 

### Flowgate Congestion by Time (graphical)

Figure III.6 is a graphic representa tion of flowgate congestion as highl ighted 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 necessari ly bad, as it may signal areas where additional transmission development is needed to eliminate bottleneck s and facilitate effici ent use of system.

Figure III.6 Percent congestion by Time Status

0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100%JanFebMarAprMayJunJulAugSepOctNovDecJanFebMarAprMayJunJulAugSepOctNovDecJanFebMarAprMayJunJulAugSepOctNovDec

2008 2009 2010

Off Peak On Peak TotalSouthwest Power Pool, Inc.

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 flowga te 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 ha s 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 ha s in some months substantially exceeded 5%. Appropriate congestion management techniques should minimize the incidence of severe transmission congestion and preclude flowgate breaches of th is 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

0% 5% 10% 15%% Dispatch Intervals Breached % Intervals BreachedSouthwest Power Pool, Inc.

SPP 2010 State of the Market Report 77 

### Binding Flowgates

Figure III.8 shows the to tal 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 bei ng fully utilized. A binding flowgate indicates the transmission system is functio ning as efficiently as possible given its current condition and configuration.

Figure III.8 Intervals with Binding Flowgates

0% 20% 40% 60% 80% 100%% Dispatch Intervals Binding % Intervals BindingSouthwest Power Pool, Inc.

SPP 2010 State of the Market Report 78 

### Constrained Flowgates by Time

In the SPP region there are flowgate s that are congested/c onstrained a significan t amount the time. Figure III.9 lists the top 20 c onstrained 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 tr ansmission 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%Southwest Power Pool, Inc.

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 cat egorized by binding or breached conditions. For example, for every 2010 inte rval in which there was a binding flowgate, its associated shadowprice is summ ed 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 89,036 212,916 301,952Southwest Power Pool, Inc.

SPP 2010 State of the Market Report 80 

### C. Transmission Outages

Transmission elements experience outages during whic h they are not in servic e and not available for use. Outages may be the result of maintenance or some other scheduled un availability, or may be caused by unforeseen circumstances such as storm damage, accidents, fires, etc.



### Transmission Outage Days

Figure III.11 shows total transm ission outage days for 2004-2010. A transmission outage day is the total number of days in which a transmission elem ent 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 increas ed dramatically. There are several reasons for this, including the additi on of new market participants and ne w transmission elements to the SPP system. Reporting of transmission outages has in creased, 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

0 5000 10000 15000 20000 25000 30000

2004 2005 2006 2007 2008 2009 2010

System TotalSouthwest Power Pool, Inc.

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 seve ral reasons. Some indica tors suggest that the market footprint has experienced increased mainte nance 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, transm ission outages only become a concern when a corresponding increase in congestion is observe d. 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 tran smission 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 ma kes sense to schedule transmission outages when there is less demand on the transmission system.

Figure III.12 Days of Transmissi on Outage by Month for 2004 – 2010

0 500 1000 1500 2000 2500 3000

Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec

2004 2005 2006 2007 2008 2009 2010Southwest Power Pool, Inc.

SPP 2010 State of the Market Report 82 

### Transmission Outage Days by Balancing Authority

Figure III.13 shows total days of transmission out ages by Balancing Authority for 2010. The largest participants consistently experi enced the most outage days. This is expected, because the largest participants have more transmission faciliti es and have more cause for outages.

Figure III.13 Days of Transmission Outages by Balancing Authority

0 500 1000 1500 2000 2500 3000 3500 4000 4500 5000

CSWS OKGE NPPD WR SPS KCPL LES EDE GRDA SECI OPPD MPS INDN KACY WPEKSouthwest Power Pool, Inc.

SPP 2010 State of the Market Report 83 

### Relative Repair Time for Transmission Outages

Figure III.14 shows the ratio of transmission outag e days compared to the number of transmission facilities by participant. This char t establishes the number of outage days per element by participant. The chart depicts considerable diversity because th ere 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

0 2 4 6 8 10 12 14Southwest Power Pool, Inc.

SPP 2010 State of the Market Report 84 

### D. Generator Outages

Generator outages typically fall into two categorie s, forced and maintenance. Forced outages occur when a generator is unable to function at full capac ity due to an unforeseen circumstance, or it has otherwise been rendered inoperativ e. 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 out ages to ameliorate wit hholding of such type.

Figure III.15 shows total forced and maintenance generation out ages 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. Outa ges 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 ma intenance 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 generati on 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

0% 5% 10% 15% 20% 25%

0 1000 2000 3000 4000 5000 6000 7000 8000 9000 10000 1100001JAN200825JAN200818FEB200813MAR200806APR200830APR200824MAY200817JUN200811JUL200804AUG200828AUG200821SEP200815OCT200808NOV200802DEC200826DEC200819JAN200912FEB200908MAR200901APR200925APR200919MAY200912JUN200906JUL200930JUL200923AUG200916SEP200910OCT200903NOV200927NOV200921DEC200914JAN201007FEB201003MAR201027MAR201020APR201014MAY201007JUN201001JUL201025JUL201018AUG201011SEP201005OCT201029OCT201022NOV201012/16/2010

FORCED OUTAGE MAINTENANCE OUTAGE PERCENT OUTAGESouthwest Power Pool, Inc.

SPP 2010 State of the Market Report 85 

### E. Generation Interconnection (2010)

In order for generation to be added to the SPP foot print, it is necessary to perform engineering
studies to determine the feasibili ty of the proposed generation connecting to the system and to identify any transmission development that is nece ssary to facilitate the proposed generation. Types of engineering studies include: Feas ibility, PISIS, DISIS, and Facil ity. Generation under these study types is displayed in Figure III .16. Generation studies th at have already been completed are also included in the figure. These include those interc onnection 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 – Initia l 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 co st allocations for necessary transmission upgrades (if any) •Definitive Interconnection System Impact Study (DISIS) - More detailed analysis of the proposed interconnection with co st allocations for necessary transmission upgrades (if any), and system response modeling with updated interconnec tion parameters •Facility Study Stage – Final analysis of proposed interconnection including detailed cost planning data, complete analysis of system in tegration impacts highlig hting needed upgrades. •Interconnection Agreement (IA) Pending – The Customer, SPP and the Transmission Operator are in the process of nego tiating aspects of the Genera tion Interconnection Agreement 0 1000 2000 3000 4000 5000 6000 7000 8000 9000 10000

FEASIBILITY STUDY
STAGE PISIS STAGE DISIS STAGE FACILITY STUDY
STAGE IA PENDING IA FULLY EXECUTED/ON

SCHEDULE IA FULLY EXECUTED/ON

SUSPENSIONSouthwest Power Pool, Inc.

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 outl ined 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 generati on interconnection request s 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 ove r 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)

0 2000 4000 6000 8000 10000 12000 14000 16000 18000 20000

Coal Gas Hydro Wind Solar OtherSouthwest Power Pool, Inc.

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 sy stem, 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. Th e 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 rema ins 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 th an $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 c ongested 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 effort s for these congested ar eas. Additionally, the recognition that the current conge stion experienced by ma rket participants should be studied and where possible resolved is a majo r undertaking that should yield posit ive results for all parties.Southwest Power Pool, Inc.

SPP 2010 State of the Market Report 88 

## IV. Market Developments

The following issues relate to the SPP market but ar e not directly represented by other metrics. This section highlights macro trends th at may affect the SPP region, and di scusses issues that may bring gains if new structures ar e adopted or incorporated.



### A. Integrated Mark etplace Design Issues

The proposed Integrated Marketpla ce design is an extensive reform of SPP’s existing markets that will introduce a Day-Ahead Market with Transmi ssion Congestion Rights (TCR), a Reliability Unit Commitment process, and a Real-Time Balanc ing Market. Beginning in September 2009, an MMU representative attended Market Working Group (M WG) meetings in which Marketplace design was discussed. The MMU discussed critical design elem ents 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 Mo nitoring Plan and Mitigation Measures. The following sections highlight the In tegrated Marketplace design’s st rengths and weaknesses, focusing on implications of the proposed rules’ efficiency and competitiveness.



### MMU Supports

The MMU supports most of the proposed Inte grated 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 margi n. 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-optim ization 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 Partic ipants. 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 applicat ion in other markets.



### MMU Concerns

The MMU was opposed to the following design el ements, and expressed its concern to both the MWG and the SPP Board of Directors. Consequentl y, the MWG has since revi ewed these issues andSouthwest Power Pool, Inc.

SPP 2010 State of the Market Report 89 has modified the market design by removing th e 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 Reserv e Zone obligations between Reserve Zones

Restriction on the Reserve Zone Minimum

The Reserve Zone minimum was originally restrict ed 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 availabl e 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 th e 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) – Unus ed import capability (100 MW) = 400 MW 2) Reserve Zone load (800 MW) – Unused import capability (100 MW) = 700 MW 3) Sum of Available Operating Reserv e 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 ASouthwest Power Pool, Inc.

SPP 2010 State of the Market Report 90 loss of the 500 MW resource. Yet under the prop osed 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 prece ded 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 a nd generation resources, and thwart
innovation." 2

FERC continued in the same NOPR:

"Without prices that reflect the true va lue of energy, we cannot expect the full integration of demand response into or ganized markets. We therefore do not
believe that reforms in this area should be delayed until ev ery barrier to demand response, whether retail or wholesale, t echnological or regulat ory, is identified
and addressed."

Subsequently, in Order 719 FERC recommended four different approaches for applying scarcity pricing in RTO/ISO markets and required each RT O/ISO to implement scarcity pricing and better reflect the true value of energy dur ing operating reserve shortages.

The MMU argued that the restriction on the Op erating Reserve zone minimum precluded the appropriate application of scarcity prices and effectively negated the beneficial price signals and efficiency gains that should be obtai ned 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 obliga tions to a generator th at is outside of the Reserve Zone. This provision, which to our know ledge 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 ob ligation transfer requires some
assurance that the rese rves, if called on, would be deliverable to the Reserve Zone where the obligation originated. If the reserv es were not deliverabl e, 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, transm ission 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.Southwest Power Pool, Inc.

SPP 2010 State of the Market Report 91 been reduced by the amount of the obligation tran sfer. Thus, the restricted transmission capacity would not have been available for energy impor ts and congestion resolution. This would have reduced the effectiveness of the co-optimization of energy and reserves. Th is design element also would have presented potential market power abuse opportunities. This provision would have enabled a select group of members, those holding fi rm 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 mark et and thus introduced gaming issues.

This design element would have presented anothe r 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 va lue that accrued to the firm transmission rights holder would be obtained through the TCR Market. With the submittal of a reserve obligation transfer schedu le, 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 de sign elements, the MMU had very serious concerns regarding Reserve Zone obliga tion 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 Part icipants to hedge these risks. Differences in
reserve costs between two settlemen t locations should always be lowe r than the differences in energy costs due to the co-optimization of energy and rese rves. 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 MW G to proceed with a request to further evaluate the be nefits 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 MW G 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.Southwest Power Pool, Inc.

SPP 2010 State of the Market Report 92 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 fo r adjusting the ARR nomination caps 2. Remove the provision allowing the Reserv e 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 whic h there are significant cr oss 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 Elect ricity Coordinating Council. S eams occur at the borders of entities’ footprints where regiona l operational and stru ctural differences cau se a discrepancy in prices, cost allocations, and respons e characteristics to c onstrained 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 developm ent of consistent practices and congestion management strategies for Reciprocally Coordi nated flowgates in the Eastern Interconnection. Consequently, the CMPWG is highly involved in activ ities 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 re quiring further study and resolution:

• Improvement of market flow calculations

• Improvement of coordinated planning

• Comprehensive cost allocation methodology

• Parallel flow visu alization methodologySouthwest Power Pool, Inc.

SPP 2010 State of the Market Report 93 

### Improvement of Market Flow Calculations

Over the past several years, SPP has observed subs tantial amounts of unattri buted flows over several flowgates near the border with MISO. Studies indicated the un attributed flows were largely explained by differences in th e methodologies used by MISO and SPP to calculate market flows. This untagged parallel flow has both reliability an d equity implications. The untagged flow has
accounted for as much as 40% of the total flow gate capacity on certain flowgates near the SPPMISO border; this is well over th ree times the normal. To addr ess this problem, SPP, MISO and PJM developed a task force, whic h reports to the CMPWG, to re view the situation and develop options for improvements in the market flow calculation methodology. Various solutions were proposed, and a set of recommendations were deve loped and will be presented for approval to the appropriate entities. Due to the significant financia l and reliability implicatio ns of this problem, the MMU strongly encourages the affected parties to develop a prompt a nd equitable solution.



### Improvement of Coordinated Planning

A perennial issue that ar ises across the Eastern Interconnection is development and cost allocation of transmission infrastructure that spans regi onal boundaries. SPP established some limited
coordination of transmission infrastructure de velopment through the Integrated Transmission Planning process, and participates in interregional organizations such as ISO/RTO Council and the Eastern Interconnection Planning Co llaborative. Broader use of coor dinated planning is necessary, and SPP is actively working to increase stakeholder support for this endeavor. SPP will participate in discussions in which modeling assumptions, coordina ted solutions for problems, and cost allocation methodologies that are equitable for member organizations will be developed.



### Comprehensive Cost A llocation Methodology

A comprehensive interregional cost allocation methodology is needed to ensure that costs associated with flowgate congestion and transmission develo pment are appropriately borne by the affected parties. The SPP Seams Steering Committee develope d cost allocation principles in 2010, and SPP has begun discussions with neighbo ring entities regarding incorporat ion of these principles into various seams agreements.



### Parallel Flow Visualization Methodology

Consistency in market flow methodologies is impe rative as the bulk electric system becomes more interconnected. The North American Energy Stan dards Board (NAESB) is developing a single prioritizing methodology with which to consolidate and replace different market flow methodologies maintained by various regions. Two options ar e currently under cons ideration by the NAESB: requiring tagging of all non-firm re sources, 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.Southwest Power Pool, Inc.

SPP 2010 State of the Market Report 94 

### Summary and Conclusions

As part of an interconnected transmission system, SPP has the obligation to en sure that its interests are represented throughout th e bulk electric system. It is entirely appropriate for SPP to work with its neighbors to develop policies and pr ocedures that establish efficien cy and equitable transactions across seams. SPP is participating in several initiatives that shoul d encourage long-term efficiency throughout the interconnected regions.Southwest Power Pool, Inc.

SPP 2010 State of the Market Report 95 

### 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 drilli ng technologies and formation fract uring processes. Innovations in these areas have dramatically decreased the cost of exploring shale gas formations. Consequently, previously uneconomic formations are being de veloped for commercial use and production from
these fields is in creasing rapidly.

Shale gas development is an important considera tion for the SPP region. Nume rous significant shale gas areas are either entirely or partially with in the SPP area, including th e 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 develo pment 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 subs tantial price differentials between different regions of the country, as the total capacity to move gas between the re gions 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. Expansi on of exploration into previously uneconomic shale plays, coupled
with the dramatic decrease in the cost of drilli ng 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 constructi on, the total transfer cap acity of natural gas has also increased. Consequently, natural gas prices ar e 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 co st estimates reflect th e fundamental shift in assumptions surrounding natural gas production. Th e MMU reviewed changes in the natural gas market and has the following three questi ons 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?Southwest Power Pool, Inc.

SPP 2010 State of the Market Report 96 • 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, efficien t, and effective models and
estimates.Southwest Power Pool, Inc.

SPP 2010 State of the Market Report 97 

### D. SPP Congestion Management Changes

Transmission Loading Relief (TLR)/Conges tion Management Event (CME) Procedure
Review

To manage congestion SPP uses se veral relief mechanisms, principally the Transmission Loading Relief (TLR) and Congestion Management Event (CME ) processes. In the pa st the TLR process was the sole method for ameliorating excessive flowga te loading. An SPP tariff requirement specified that the TLR process must be utilized even wh en no Interchange Distri bution Calculator (IDC) curtailable schedules existed. The TLR process is best suited for instances when there are IDC curtailable schedules, so the requirement that th e 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 sche dules, it became necessa ry to develop a secondary mechanism to more efficiently manage flowgate congestion.

The secondary mechanism for better managing c ongestion is the Congestion Management Event procedure, which was implemented in August 2 010. 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-dispa tch 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 necessa ry to use the TLR process when there are no associated IDC curtailable schedules; this is principally the ca se when a flowgate is affected by only market resources and schedules. However, if there are IDC curtailable sche dules, 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 n eeded. The CME procedure reduces
the total incidence of TLR re porting, providing a better basis of comparison with neighboring entities. The CME procedure, which has a faster re sponse time than the TLR process, should result in faster mitigation of congestion management.



### Early Results of CME Implementation

The following figure summarizes congestion stat istics for 2009 and 2010, highlighting changes before and after the CME procedure implementati on. The CME procedure resulted in a decline of over 4,000 total TLR hours. This is a substantial d ecrease, and indicates ho w extensively the TLR process was over reporting congestion in past year s. The displacement of the TLR process by the CME procedure represents an improvement in the congestion management process for the SPP market system.Southwest Power Pool, Inc.

SPP 2010 State of the Market Report 98 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 TotalSouthwest Power Pool, Inc.

SPP 2010 State of the Market Report 99 

## 2010 Conclusions and Recommendations

SPP Market Performance

The SPP wholesale electric market c ontinues to be competitive, and ove rall market participation is at very high levels. Generation from resources that use Self-Dispatched st atus (self-scheduled)
continues to decline and is now at about 1-2% of to tal 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 dec lining levels of revenue neutrality uplift. One area of concern is th e decline in dispatchable rage offered by Market Participants.

Prices in the SPP region are well in line with expect ations. Average prices are up slightly more than 14%, which closely corresponds with the change in th e 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 ma y become stronger should natural ga s 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 pric e volatility. SPP volatility is sligh tly less than MISO and about half of what is experienced in ERCOT.



### Competitive Market

The MMU considers the SPP EIS market to be wo rkably 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-concentr ated. 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. C ongestion will create conditions where there will be very high levels of concentr ation and limited competition.

Because congestion creates conditions where individua l 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 o ffer caps have very little impact on prices in the SPP market. This is one indi cation that offers are generally competitive.Southwest Power Pool, Inc.

SPP 2010 State of the Market Report 100 

### Localized Conges tion Concerns

The SPP system contains some highly congested tran smission corridors that result in significant, local price volatility. The aver age annual price for the system was $31.33 in 2010. While specific load serving entities, with variable constraine d conditions, experienced average annual prices ranging from $35.18 to $25.45. This is also reflect ed in the price vola tility for individual participants. The SPP system price volatility is on ly 50% whereas individual participants experience volatility as high as 113%. The volatility and price differentia l 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 seve ral 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 tran smission projects have be en developed to help alleviate this congestion. Thes e projects have an in-ser vice 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 gene ration 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 tr ansmission capacity is constructed. Transmission development scheduled to be in service in 2014 should help redu ce this congestion.



### Seams Issues

RTO’s with different market rules and business practices may encounter difficulty in managing congestion, and in establishing effective and effici ent operations at their borders (seams). The different rules and practices may result in price di stortions and inefficient cost allocation between
entities at the seams. These seams issues can b ecome especially pronounce d 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 direc tly impact by the congestion in the Kansas City area have been diligently identifying seams-rela ted concerns and are developing mechanisms to
address these issues. The RTO’s ha ve established a number of task forces and working groups to enhance communication and reach equitable solu tions for all involved. Given the levels of congestion in the affected area, a nd the potential for signi ficant financial implicat ions, it is important
that the involved RTO’s resolve thes e issues as swiftly as possible.Southwest Power Pool, Inc.

SPP 2010 State of the Market Report 101 

### Integrated Marketplace Design

The SPP Market Working Group and the SPP Market De sign team established a goal of developing an Integrated Marketplace design that incorporated the best com ponents 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 propos ed market protocols create a sound base for moving forward with the development of the Integrated Market Place.Southwest Power Pool, Inc.

SPP 2010 State of the Market Report 102 

## Definitions of Select Terms

Alternating Current - the movement of electric charge th at periodically re verses 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 wh en no curtailable transactions in the IDC are
present Direct Current - the movement of unidirectional electric charge Energy Imbalance Service - the real time balancing betwee n scheduled generation and load Energy Imbalance Service Market - the overall market structur e 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 electr ical 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 nume ral 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 el ectrical energy e qual to 1,000,000 Watts Mega-watt hour - A measure of electrical energy equa l 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 b ack to participants Regional Transmission Organization - Organization responsible fo r moving electric ity over large areas, commonly at higher voltages and ove r larger areas than covered by an ISO Transmission Loading Relief - A process used to reduce loading on lines which are at risk for an
overloadSouthwest Power Pool, Inc.

SPP 2010 State of the Market Report 103 

## 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 Ener gy 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 & Li ght, Independence, Missouri IOU Investor-Owned Utility IPP Independent Power Producer ISO Independent System Operator
KACY Board of Public Utili ties, 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 GasSouthwest Power Pool, Inc.

SPP 2010 State of the Market Report 104 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 Interconne ction 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 Electr icity Coordinating Council WERE Westar Energy, Incorporated WFEC Western Farmers Electric Cooperative