Southwest Power Pool, Inc., Docket No. ER13- Submission of Filing to Update Energy Imbalance Market Offer Cap

November 7, 2012 The Honorable Kimberly D. Bose Secretary Federal Energy Regulatory Commission 888 First Street, N.E. Washington, D.C. 20426 Re: Southwest Power Pool, Inc., Docket No. ER13- Submission of Filing to Update Energy Imbalance Market Offer Cap Dear Secretary Bose: Pursuant to section 205 of the Federal Power Act, 16 U.S.C. 824d, and section 35.13 of the Commission s regulations, 18 C.F.R. 35.13, Southwest Power Pool, Inc. ( SPP ), submits this filing revising its Open Access Transmission Tariff ( Tariff ). Specifically, SPP is incorporating Tariff revisions in order to reflect updates of annual values used in the calculation of offer caps for all pivotal resources in SPP s real-time energy imbalance service market ( EIS Market ). SPP requests an effective date of January 1, 2013, for the Tariff modifications. In support, SPP states the following: I. Background On January 4, 2006, SPP filed with the Commission proposed Tariff revisions to implement an EIS Market and establish a market monitoring and market power mitigation plan. 1 The 2006 Filing included a proposed Section 3.2.4 of Attachment AF, which detailed how SPP would calculate its offer cap during periods of transmission constraints. Specifically, SPP proposed to use the following formula: Offer Caps will be equal to the sum of (a) the estimated annual fixed cost of a new, natural gas-fired, combustion turbine peaking generation facility in $/megawatt-year [ AFC ] divided by the annual hours of constraint [ AHC ], (b) an adder equal to the estimated non-fuel variable operation and maintenance costs of a new, natural gas-fired, combustion turbine peaking generation facility in $/megawatt-hour [ VOM ], and (c) the fuel cost of the peaking facility in $/megawatt-hour [ FC ] calculated as the 1 See Submission of Tariff Revisions to Incorporate Energy Imbalance Market and Market Monitoring Procedures of Southwest Power Pool, Inc., Docket No. ER06-451-000 (Jan. 4, 2006) ( 2006 Filing ).

The Honorable Kimberly D. Bose November 7, 2012 Page 2 of 6 heat rate multiplied by a natural gas price index. The formula for the calculation is as follows: Offer Cap = (AFC / AHC) + VOM + FC. 2 Boston Pacific Company, Inc. ( Boston Pacific ), on behalf of SPP, proposed to calculate the AFC of a generic combustion turbine by extrapolating from U.S. Energy Information Administration ( EIA ) data to produce a fixed cost per megawatt-year. Boston Pacific also proposed a VOM adder per megawatt hour based on inflation-adjusted EIA data for a combustion turbine. The Boston Pacific testimony included in the 2006 Filing explained the underlying assumptions Boston Pacific used to determine the AFC and VOM used to calculate the first offer cap. In addition, SPP s proposal provided that any changes to these costs, along with justification for the changes, would be filed with the Commission for approval. The Commission accepted SPP s proposals in an order issued on March 20, 2006. 3 Since the Commission s approval of the EIS Market, SPP has filed annual revisions to reflect updates of variables used in the calculation of offer caps in the EIS Market. 4 II. Description and Justification for Tariff Revisions SPP submits the Tariff revisions in this filing to reflect the annual updates of AFC and VOM used in the offer cap calculation. The update maintains many of the original assumptions in the model used to determine the offer cap, proposed in the Boston Pacific testimony, which the Commission approved in the 2006 Order. 5 However, as explained below, SPP updates certain inputs based on the most recent data; specifically, SPP updated the annual costs of a generic combustion turbine that comes from the EIA s Assumptions to the 2012 Annual Energy Outlook, 6 as well as the interest rate utilized to determine the AFC and VOM. First, the plant size of the simple cycle gas combustion turbine, used in the EIA Assumptions to the Annual Energy Outlook, changed from 160 MW to 85 MW 2 3 4 5 6 See Tariff at Attachment AF Section 3.2.4. See Southwest Power Pool, Inc., 114 FERC 61,289, at PP 188-89 ( 2006 Order ), order on reh'g, 116 FERC 61,289, at PP 17-25 (2006). See, e.g., Southwest Power Pool, Inc., Docket No. ER12-227-000, Letter Order (Dec. 21, 2011). SPP includes as Exhibit No. 1 a list of the key assumptions used to calculate AFC and VOM. See U.S. Energy Information Administration, The Assumptions to the 2012 Annual Energy Outlook, http://www.eia.gov/forecasts/aeo/assumptions/pdf/electricity.pdf.

The Honorable Kimberly D. Bose November 7, 2012 Page 3 of 6 beginning with the 2012 update. According to EIA, the assumptions for the gas combustion turbine were updated to reflect current installations and updated cost information for annual fixed costs as well as variable O&M costs. 7 The heat rate for the 85 MW plant size, however, remains at 10,450 Btu/kWh, as it has been in previous years. Second, SPP developed the interest rate in a manner consistent with Boston Pacific s 2006 testimony. SPP adjusted all numbers to reflect values in 2013 using an inflation factor of 2.38%, which was derived from data available from the Bureau of Labor Statistics, CPI-U (All Items). Based on the updates to the assumptions and the interest rate, SPP calculated the AFC to be $133,800/MW-year and the VOM costs to be 15.79 mills/kwh or $15.79/MWh. The increase in the AFC as well as the VOM from last year primarily is due to the updated analysis by EIA, inasmuch as the other assumptions in the model remain the same. SPP submits the Tariff revisions to reflect this updated analysis. SPP also includes the worksheets providing the relevant calculations as Exhibit No. 1. As stated above, the updated analysis was completed using the same methodology, as well as the same reliable data sources and reasonable assumptions, that the Commission approved in the 2006 Order. 8 In addition, the Commission has previously accepted substantially similar filings by SPP to update its EIS Market offer caps. 9 SPP thus submits that the revisions proposed in this filing are just and reasonable. 7 8 9 Id. at Table 8.2. The cited Assumptions present the cost and performance characteristics of new central station electricity generating technologies. They also provide the source of the EIA-commissioned external consultant report that developed current estimates for utility-scaled generating plants. See http://www.eia.gov/oiaf/beck_plantcosts/index.html. See 2006 Order at P 189. See Southwest Power Pool, Inc., Letter Order, Docket No. ER12-227-000; Sw. Power Pool, Inc., Letter Order, Docket No. ER11-1930-000 (Dec. 8, 2010); Sw. Power Pool, Inc., Letter Order, Docket No. ER10-126 (Dec. 11, 2009); Sw. Power Pool, Inc., Letter Order, Docket No. ER09-140-000 (Dec. 11, 2008); Sw. Power Pool, Inc., Letter Order, Docket No. ER08-108-000 (Dec. 18, 2007).

The Honorable Kimberly D. Bose November 7, 2012 Page 4 of 6 III. Effective Date SPP requests an effective date of January 1, 2013, for the Tariff modifications submitted in this filing. In addition, SPP respectfully requests that the Commission issue an order approving the proposed Tariff revisions no later than December 28, 2012, which is 51 days after this filing. In order for the calendar year 2012 offer caps to be calculated for January 1, 2013, the components of the calculation must be in place in SPP s database production system no later than December 30, 2012, at 1500 (CST). Commission approval by December 28, 2012, will provide SPP with sufficient time to make the necessary changes in its database so that the updated offer caps will be in place by January 1, 2013. IV. Additional Information A. Information Required by Section 35.13 of the Commission s Regulations, 18 C.F.R. 35.13: 10 (1) Documents submitted with this filing: In addition to this transmittal letter, the following material is provided with this filing: (a) clean and redline Tariff revisions under the Sixth Revised Volume No. 1, and (b) attached as Exhibit No. 1, worksheets providing the relevant calculations and assumptions. (2) Effective date: SPP requests an effective date of January 1, 2013, for the proposed Tariff modifications. 10 SPP requests any waiver deemed necessary to utilize the abbreviated filing procedures set forth in section 35.13(a)(2) of the Commission s regulations, 18 C.F.R. 35.13(a)(2). Good cause exists for granting this waiver. As detailed in this filing, the increase in the offer cap is based on the mitigation formula approved by the Commission in the 2006 Order. The Commission has granted waivers in similar instances. See Mich. Elec. Transmission Co., LLC and Midwest Indep. Transmission Sys. Operator, Inc., 113 FERC 61,343 (2005) (conditionally accepting filing to increase rates for a Regional Transmission Organization pricing zone where a similar waiver request was made in initial filing).

The Honorable Kimberly D. Bose November 7, 2012 Page 5 of 6 (3) Service: SPP has served a copy of this filing on all its Members and Customers, as well as on all affected state commissions. A complete copy of this filing will also be posted on the SPP web site, www.spp.org. (4) Description of filings: A description of changes, along with the reasons for these changes, is provided above. (5) Requisite agreements: None. (6) Costs alleged or judged illegal, duplicative, or unnecessary: None. (7) Basis of rates: The bases for the offer cap changes are explained above. (8) Specifically assignable facilities installed or modified: None. B. Communications: Correspondence and communications with respect to this filing should be sent to, and SPP requests the Secretary to include on the official service list, the following: Nicole Wagner Manager, Regulatory Policy Southwest Power Pool, Inc. 201 Worthen Drive Little Rock, AR 72223-4936 Telephone: (501) 688-1642 Fax: (501) 664-9553 jwagner@spp.org

The Honorable Kimberly D. Bose November 7, 2012 Page 6 of 6 V. Conclusion For all of the foregoing reasons, SPP requests that the Commission accept the Tariff revisions submitted in this filing with an effective date of January 1, 2013. SPP also requests that the Commission issue its order accepting the proposed Tariff revisions no later than December 28, 2012. Respectfully submitted, /s/ Joseph W. Ghormley Joseph W. Ghormley Attorney for Southwest Power Pool, Inc. CC: Penny Murrell Michael Donnini John Rogers Patrick Clarey Laura Vallance CERTIFICATE OF SERVICE I hereby certify that I have this day served the foregoing document upon each person designated on the official service list compiled by the Secretary in this proceeding. Dated this 7 th day of November, 2012. /s/ Joseph W. Ghormley Joseph W. Ghormley Attorney for Southwest Power Pool, Inc.

Exhibit No. 1

SOUTHWEST POWER POOL, INC. Key Results for Replacement Cost Method All Prices in 2011$ Combustion Turbine Plant Results Plant Size, MW 85 Capital Recovery, $/kw-yr 126.30 Fixed O&M Costs, $/kw-yr 7.50 Total Fixed Expenses, $/kw-yr 133.80

SOUTHWEST POWER POOL, INC. Key Assumptions for Replacement Cost Method All Prices in 2010$ Assumptions by Technology Type Technology Type Factor CT EPC Cost, $/kw 868 Source BPC Estimate Soft Costs, $/kw 208 Source BPC Estimate Total Costs, $/kw 1076 Source BPC Estimate Fixed O&M Costs, $/kw-yr 7.50 Source BPC Estimate Plant Capacity 85 Source BPC Estimate Tax Depreciation Schedules 15-yr MACRS Source IRS Pub. 946 Financing Assumptions (based on BPC experience) Debt Percent 50.0% Interest Rate 5.25% Debt Term, years 15 Repayment Schedule (EPP or Mortgage) EPP Min. DSCR 1.5 Target Equity IRR 12.50% Equity Horizon, years 20 Other Assumptions Depreciation of Soft Costs 5-yr 150% DB Source BPC Models Federal Tax Rate 35.00% State Tax Rate 6.00% Combined Tax Rate 38.90% General Inflation 2.38%

SOUTHWEST POWER POOL, INC. Combustion Turbine -- Fixed Operating and Capital Recovery Costs All Costs in 2010 US$ RESULTS FIXED COSTS, $/kw-yr: Capital Recovery Costs 126.30 Fixed O&M 7.50 Total Fixed Costs 133.80 INPUTS Plant Capacity, MW: 85 Financing: Escalate Capacity Payments? 1 % Debt 50.0% (1 = yes, 0 = no) Debt Loan, $000 538 % Equity 50.0% Equity Investment, $000 538 Capital Costs: $000 $/kw EPC Price 73,780 868 1,046 Land 1,500 18 Debt Terms: Legal Fees 1,250 15 Tenor, yrs 15 Development Costs 1,500 18 Interest Rate 5.25% Vehicles 150 2 Min DSCR 1.50 Mobilization 750 9 Schedule (M or EPP) EPP Independent Engineer 750 9 Contingency @ 3.0% 2,390 28 Debt Reserve Funding 2,724 32 Equity Terms Working Capital 1,862 22 Length of Investment, yrs 20 Financing Fees @ 2.5% 2,231 26 Desired IRR 12.5% IDC 2,565 30 TOTAL CAPITAL COSTS 91,452 1,076 Taxes Federal Tax Rate 35.00% Operating Costs State Tax Rate 6.00% Fixed Operating Costs, $/kw-yr 7.50 Effective Combined Rate 38.90% Equipment Depreciation 15 Inflation 2.38% IRR Check: OK Debt Repayment Check: OK

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 Revenues Capacity Revenue 126 129 132 136 139 142 145 149 152 156 160 164 167 171 176 DSR Interest and Recovery 5% 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 Total Revenue 128 132 135 138 141 144 148 151 155 158 162 166 169 173 177 Capacity-related Expenses Interest on Debt 28 26 24 23 21 19 17 15 13 11 9 8 6 4 2 Principal Payments 36 36 36 36 36 36 36 36 36 36 36 36 36 36 36 Income Tax - - 7 12 16 27 30 32 34 36 38 40 43 45 47 Total Capacity Expenses 64 62 67 70 73 81 83 83 83 83 84 84 84 85 85 Distributions to Investors (538) 64 70 68 68 68 63 65 68 72 75 78 82 85 89 92 IRR -88.1% -57.6% -36.5% -22.8% -13.7% -7.9% -3.5% -0.2% 2.4% 4.4% 6.1% 7.4% 8.4% 9.3% 10.0% DSCR 1.97 2.08 2.19 2.32 2.45 2.60 2.75 2.92 3.11 3.31 3.53 3.77 4.03 4.33 4.65 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 Debt Calculations Year-start Outstanding Liability 538 502 466 430 394 359 323 287 251 215 179 143 108 72 36 Interest Payment 28 26 24 23 21 19 17 15 13 11 9 8 6 4 2 Principal Payment 36 36 36 36 36 36 36 36 36 36 36 36 36 36 36 Income Tax Capacity Revenue 128 132 135 138 141 144 148 151 155 158 162 166 169 173 177 Interest Payments (28) (26) (24) (23) (21) (19) (17) (15) (13) (11) (9) (8) (6) (4) (2) Depreciation (108) (107) (93) (85) (79) (57) (54) (54) (54) (54) (54) (54) (54) (54) (54) Taxable Base - - 17 30 42 69 77 82 88 93 99 104 110 116 122 Income Tax 38.90% - - 7 12 16 27 30 32 34 36 38 40 43 45 47 Depreciation Equipment 914 80 83 75 68 61 55 54 54 54 54 54 54 54 54 54 Soft Costs 108 28 24 18 18 18 2 - - - - - - - - - Total Depreciation 1,022 108 107 93 85 79 57 54 54 54 54 54 54 54 54 54 Page 4 of 6 SOUTHWEST POWER POOL, INC. Pro Forma for the Calculation of Required Capacity Recovery for a New Combustion Turbine Plant All Figures are in $/kw-yr IRR for Target Term 12.5% Target IRR 12.5%

Page 5 of 6 SOUTHWEST POWER POOL, INC. 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 180 184 188 193 197 202 207 212 217 222 227 233 238 244 250 19 - - - - - - - - - - - - - - 199 184 188 193 197 202 207 212 217 222 227 233 238 244 250 - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 75 72 73 75 77 79 81 82 84 86 88 91 93 95 97 75 72 73 75 77 79 81 82 84 86 88 91 93 95 97 124 112 115 118 121 124 126 129 133 136 139 142 146 149 153 10.8% 11.3% 11.8% 12.2% 12.5% 12.8% 13.0% 13.2% 13.4% 13.5% 13.6% 13.7% 13.8% 13.9% 14.0% n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 199 184 188 193 197 202 207 212 217 222 227 233 238 244 250 - - - - - - - - - - - - - - - (7) - - - - - - - - - - - - - - 192 184 188 193 197 202 207 212 217 222 227 233 238 244 250 75 72 73 75 77 79 81 82 84 86 88 91 93 95 97 7 - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 7 - - - - - - - - - - - - - -

Year Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Annual HALF1 HALF2 Annual Growth Half Year Growth 2001 175.1 175.8 176.2 176.9 177.7 178 177.5 177.5 178.3 177.7 177.4 176.7 177.1 176.6 177.5 2002 177.1 177.8 178.8 179.8 179.8 179.9 180.1 180.7 181 181.3 181.3 180.9 179.9 178.9 180.9 1.58% 1.30% 2003 181.7 183.1 184.2 183.8 183.5 183.7 183.9 184.6 185.2 185 184.5 184.3 184 183.3 184.6 2.28% 2.46% 2004 185.2 186.2 187.4 188 189.1 189.7 189.4 189.5 189.9 190.9 191 190.3 188.9 187.6 190.2 2.66% 2.35% 2005 190.7 191.8 193.3 194.6 194.4 194.5 195.4 196.4 198.8 199.2 197.6 196.8 195.3 193.2 197.4 3.39% 2.99% 2006 198.3 198.7 199.8 201.5 202.5 202.9 203.5 203.9 202.9 201.8 201.5 201.8 201.6 200.6 202.6 3.23% 3.83% 2007 202.4 203.5 205.4 206.7 207.9 208.4 208.3 207.9 208.5 208.9 210.2 210.0 207.3 205.7 209.0 2.85% 2.55% 2008 211.080 211.693 213.528 214.823 216.632 218.815 219.964 219.086 218.783 216.573 212.425 210.228 215.303 214.429 216.177 3.84% 4.24% 2009 211.143 212.193 212.709 213.240 213.856 215.693 215.351 215.834 215.969 216.177 216.330 215.949 214.537 213.139 215.935-0.36% -0.60% 2010 216.687 216.741 217.631 218.009 218.178 217.965 218.011 218.312 218.439 218.711 218.803 219.179 218.056 217.535 218.576 1.64% 2.06% 2011 220.223 221.309 223.467 224.906 225.964 225.722 225.922 226.545 226.889 226.421 226.230 225.672 224.939 223.598 226.280 3.16% 2.79% 2012 226.665 227.663 229.392 230.085 229.815 229.478 229.104 228.850 2.35% SOUTHWEST POWER POOL, INC. Inflation Adjustment CPI Inflation Yearly Notes 2010 1.64% 101.6% 2011 3.16% 103.2% 2012 2.35% 102.3% Used Half Year Effective 3 Yr Rate 107.3% Compounded Annualize Rate 2.38% $/KW 2011 2013 Current Value from EIA Inflated for Use in Model EPC Cost $ 974.00 $ 1,046.01 FO&M $ 6.98 $ 7.50 VO&M $ 14.70 $ 15.79 Data Series Id: CUUR0000SA0 Not Seasonally Adjusted Area: U.S. city average Item: All items Base Period: 1982-84=100 Source: U.S. Dept. of Labor BLS, CPI All-Urban Consumers, US City Avg. All Items http://data.bls.gov/cgi-bin/surveymost?cu

3. Economic Withholding Energy Market Power 3.1 Principles There are two principles for mitigating Economic Withholding in the EIS Market operated by SPP. 3.1.1 Mitigate Only During Transmission Constraints Mitigation will be applied only at the time of, and in places with, transmission constraints. 3.1.2 Do Not Mitigate Below Long Run Marginal Cost of New Investment Mitigation should not create or exacerbate a supply shortage by capping prices below the level needed to attract investment that would relieve the shortage. This level shall be based on the long run marginal cost of the least-cost generation supply that could be developed within the shortest period of time, which is currently a new, natural gas-fired combustion turbine, peaking generation facility. 3.2 Mitigation Measure When any transmission constraint is binding in the EIS Market, the Offer Curve prices associated with Resources with Generator-to-Load Distribution Factors that are greater than or equal to 5% that are located on the importing side of each constraint shall be no higher than the Offer Cap for each Resource. 3.2.1 Location and Determination of Binding Constraints Binding transmission constraints in the EIS Market will be located on groups of transmission elements designated as flowgates. The determination of whether a transmission constraint is binding in the EIS Market will be based on the SPP Congestion Management process and the EIS Market security constrained dispatch process for such determination. 3.2.2 Determination of Offer Capped Resources An Offer Cap, as calculated in accordance with Section 3.2.4, shall apply to certain Resources, regardless of ownership, that are on the same side of a constrained flowgate as the constrained load and within electrical proximity to the constrained flowgate. Such Resources subject to the Offer Cap will be determined for each flowgate through the use of

Generator-to-Load Distribution Factors. All Resources that are located on the importing side (side with the constrained load) of a constrained flowgate that have Generator-to-Load Distribution Factors greater than or equal to 5% (i.e., for each 100 MW increase in Resource output, the imports across the flowgate are reduced by 5 MWs or greater) shall be subject to an Offer Cap. If any of a Market Participant s Resources are subject to the Offer Cap based on the Generator-to-Load Distribution Factors, all Resources owned by that Market Participant that are located on the importing side of the same constrained flowgate shall also be subject to an Offer Cap. A list of all Resources subject to an Offer Cap and the Offer Caps associated with such Resources shall be posted electronically on a daily basis by the Transmission Provider for each flowgate. 3.2.3 Reassessment of Affected Status The Transmission Provider will reassess the status of Resources subject to Offer Caps when transmission and generation facility additions, outages, changes, or changes in ownership occur that may reasonably cause the Offer Capped status to change. In any event, the Transmission Provider will reassess the status of Offer Capped Resources on an annual basis. 3.2.4 Calculation of Offer Caps The Offer Cap for each Resource subject to an Offer Cap will be calculated at least daily and will be effective until replaced by a new Offer Cap. Specifically, Offer Caps will be equal to the sum of (a) the estimated annual fixed cost of a new, natural gas-fired, combustion turbine peaking generation facility in $/megawatt-year divided by the annual hours of constraint, (b) an adder equal to the estimated non-fuel variable operation and maintenance costs of a new, natural gas-fired, combustion turbine peaking generation facility in $/megawatt-hour, and (c) the fuel cost of the peaking facility in $/megawatt-hour calculated as the heat rate multiplied by a natural gas price index. The formula for the calculation is as follows: Offer Cap = (AFC / AHC) + VOM + FC Page 2

wherein the variables are defined as: AFC = Annual Fixed Cost (Annual Investment Recovery Requirement ($/megawatt-year) + Annual Fixed Operations and Maintenance Adder ($/megawatt-year)) AHC = Annual Hours of Constraint VOM = Variable Non-Fuel Operations and Maintenance Adder ($/megawatt-hour) FC = Fuel Cost (Heat Rate * Natural Gas Price Index) ($/megawatt-hour) Offer Caps do not function as price caps on the EIS Market. Resources other than Resource identified under Section 3.2.2 are not subject to an Offer Cap. These Resources may bid higher than, and set a price in the EIS Market that is above any Offer Cap. During periods of constraint on flowgates, Market Participants with Resources subject to Offer Caps as identified under Section 3.2.2 are restricted to submitting Offer Curve prices at or below their respective Offer Caps. All Resources, including those Resources identified under Section 3.2.2, will be charged/compensated based upon the Locational Imbalance Price associated with each Resource. (a) Annual Fixed Cost The annual fixed cost of a new, natural gas-fired, combustion turbine peaking generation facility shall be based upon the calculated value of the annual carrying cost associated with the recovery of the total fixed costs to develop, build and finance such a facility plus the fixed operation and maintenance costs. Such costs shall be reviewed annually by the Transmission Provider with input from Market Participants. Any changes to such costs, along with justification for the changes, shall be filed with the Commission for approval after such review. Such costs, along Page 3

(b) (c) with any studies justifying the costs, shall be posted electronically by the Transmission Provider. For calendar year 2013, the Annual Fixed Cost shall be equal to $133,800/Megawatt-year. Variable Non-Fuel O&M Adder The adder equal to the estimated non-fuel variable operation and maintenance costs of a new, natural gas-fired, combustion turbine peaking generation facility shall be based on the non-fuel operating and maintenance costs of such a facility not included in the calculation of annual fixed costs as described above. Such cost shall be reviewed annually by the Transmission Provider with input from Market Participants. Any changes to such costs, along with justification for the changes, shall be filed with the Commission for approval after such review. Such costs, along with any studies justifying the costs, shall be posted electronically by the Transmission Provider. For calendar year 2013, the Variable Non-Fuel O&M Adder shall be equal to $15.79/Megawatt-hour. Annual Hours of Constraint The annual hours of constraint will be calculated individually for each affected Resource under Section 3.2.2 of a Market Participant and will be based on the most recent 365 days (366 days for a leap year) of total hours of constraint in the EIS Market for constrained flowgates affecting each Resource. In the event that multiple constraints simultaneously affect a Resource, overlapping hours of constraint will be eliminated from the Offer Cap calculation for such a Resource. During the first year of operation of the EIS Market, the hours of duration for TLR Level 3 and above events for each flowgate shall be used as a proxy for hours of constraint in the EIS Market that are included in the calculation of annual hours of constraint. The annual hours of constraint will be updated daily for inclusion in the Page 4

daily calculation of the Offer Cap on each affected resource and will be posted electronically by the Transmission Provider for each Resource. (i) New Flowgates When a new flowgate is established, the annual hours of constraint used in the calculation of the Offer Cap for each Resource that is pivotal to the new flowgate will be 32 hours until the actual number of hours of constraint on the flowgate has exceeded 32 hours. After 32 hours has been reached, the actual hours of constraint will be used. After the flowgate has been active for 12 months, the Offer Cap calculation will only use the actual constrained hours for the 365 day (366 for leap year) rolling sum. If a Resource is pivotal to more than one flowgate, the minimum applies to the sum of all the flowgates for the first year of the new flowgate. (d) Fuel Cost The fuel cost of a new, natural gas-fired, combustion turbine peaking generation facility shall be based on the estimated fullload heat rate of the facility multiplied by a fuel price index. The fuel price index for each Resource will be based on an industry accepted natural gas pricing index for the natural gas pricing point nearest to the Offer Capped Resource(s) of each Market Participant. The fuel price shall be further modified based on an estimate of the distribution cost for moving natural gas to the affected resource(s). Alternative pricing points and fuel price modifiers shall be evaluated annually by the Transmission Provider with input from Market Participants. The fuel price portion of each Offer Cap shall be recalculated daily for inclusion in each Offer Cap. As of the date that this Plan is accepted for filing by Page 5

the Commission, the heat rate used in the Fuel Cost calculation shall be equal to 10,450 Btu/kWh. 3.3 Imposition of Mitigation Offer Caps will be imposed when any transmission constraint is binding in the EIS Market as determined by SPP s Market Operators through the SPP Congestion Management process and the EIS Market security constrained dispatch process. Offer Caps will only be applied to the Resources identified under Section 3.2.2. 3.3.1 Exceptions Market Participants with Offer Capped Resources may request an exception to an Offer Cap for a Resource. If the Transmission Provider after consultation with the Market Monitor determines that an exception is reasonable, the Transmission Provider shall submit a filing with the Commission. Market Participants also may submit a filing with the Commission seeking an exception. Page 6

(b) (c) with any studies justifying the costs, shall be posted electronically by the Transmission Provider. For calendar year 20122013, the Annual Fixed Cost shall be equal to $138,490133,800/Megawattyear. Variable Non-Fuel O&M Adder The adder equal to the estimated non-fuel variable operation and maintenance costs of a new, natural gas-fired, combustion turbine peaking generation facility shall be based on the non-fuel operating and maintenance costs of such a facility not included in the calculation of annual fixed costs as described above. Such cost shall be reviewed annually by the Transmission Provider with input from Market Participants. Any changes to such costs, along with justification for the changes, shall be filed with the Commission for approval after such review. Such costs, along with any studies justifying the costs, shall be posted electronically by the Transmission Provider. For calendar year 2012 2013, the Variable Non-Fuel O&M Adder shall be equal to $8.4915.79/Megawatt-hour. Annual Hours of Constraint The annual hours of constraint will be calculated individually for each affected Resource under Section 3.2.2 of a Market Participant and will be based on the most recent 365 days (366 days for a leap year) of total hours of constraint in the EIS Market for constrained flowgates affecting each Resource. In the event that multiple constraints simultaneously affect a Resource, overlapping hours of constraint will be eliminated from the Offer Cap calculation for such a Resource. During the first year of operation of the EIS Market, the hours of duration for TLR Level 3 and above events for each flowgate shall be used as a proxy for hours of constraint in the EIS Market that are included in the calculation of annual hours of constraint. The Page 4

annual hours of constraint will be updated daily for inclusion in the daily calculation of the Offer Cap on each affected resource and will be posted electronically by the Transmission Provider for each Resource. (i) New Flowgates When a new flowgate is established, the annual hours of constraint used in the calculation of the Offer Cap for each Resource that is pivotal to the new flowgate will be 32 hours until the actual number of hours of constraint on the flowgate has exceeded 32 hours. After 32 hours has been reached, the actual hours of constraint will be used. After the flowgate has been active for 12 months, the Offer Cap calculation will only use the actual constrained hours for the 365 day (366 for leap year) rolling sum. If a Resource is pivotal to more than one flowgate, the minimum applies to the sum of all the flowgates for the first year of the new flowgate. (d) Fuel Cost The fuel cost of a new, natural gas-fired, combustion turbine peaking generation facility shall be based on the estimated fullload heat rate of the facility multiplied by a fuel price index. The fuel price index for each Resource will be based on an industry accepted natural gas pricing index for the natural gas pricing point nearest to the Offer Capped Resource(s) of each Market Participant. The fuel price shall be further modified based on an estimate of the distribution cost for moving natural gas to the affected resource(s). Alternative pricing points and fuel price modifiers shall be evaluated annually by the Transmission Provider with input from Market Participants. The fuel price portion of each Offer Cap shall be recalculated daily for inclusion in each Offer Cap. As of the date that this Plan is accepted for filing by Page 5