The Honorable Kimberly D. Bose Secretary November 7, 2008 Page 2 Arkansas. SPP currently has 50 Members, serving more than 4 million customers in a 255,000 square-mile area covering all or part of eight states. SPP s members include 12 investor-owned utilities, 8 municipal systems, 11 generation and transmission cooperatives, 2 state authorities, 4 independent power producers, 11 power marketers, and 2 independent transmission companies. As an RTO, SPP is a transmission provider administering transmission service over portions of Arkansas, Kansas, Louisiana, Missouri, New Mexico, Oklahoma, and Texas. In addition to providing tariff services as an RTO, SPP serves as a Regional Entity for the North American Electric Reliability Corporation. 1 As an RTO, SPP administers provision of open access transmission service on a regional basis across the facilities that the SPP transmission owners have dedicated to the SPP Tariff. 2 The rates for transmission service under the SPP Tariff are zonal rates. SPP s zonal rates benefit all market participants by allowing customers to transmit power across the SPP region while paying only one, rather than multiple, transmission charges. For service to load located within the SPP region, the transmission rates are based on the revenue requirements for the host zone within which the load is located. 3 For service to load located outside of the SPP region, the transmission charge is based on the lowest cost zone interconnected with the control area external to the SPP Region that is the designated point of delivery, i.e., the interface between SPP and the receiving system. 4 The revenue requirement for each pricing zone is set out in Attachment H of the SPP Tariff, either in the form of a fixed revenue requirement or a formula rate. The loss factor for each pricing zone host is set forth in Attachment M, and the agreements that have been classified as Grandfathered Agreements ( GFAs ) are listed in Attachment W. On December 17, 1999, the Commission approved the use of zonal rates, subject to modifications to the revenue requirement and through-and-out transmission rates of one pricing zone host. 5 1 2 3 4 5 N. Am. Elec. Reliability Corp., 119 FERC 61,060, order on reh g, 120 FERC 61,260 (2007). See Sw. Power Pool, Inc., 89 FERC 61,084 (1999); Sw. Power Pool, Inc., 86 FERC 61,090 (1998); Sw. Power Pool, Inc., 82 FERC 61,267 (1998). See SPP Tariff at Schedules 7-9. See SPP Tariff at Schedule 7, Section 1; Schedule 8, Section 1; Schedule 9, Section 1; see also Sw. Power Pool, Inc., 89 FERC 61,284, at 61,889 (1999) ( December 17 Order ). See December 17 Order at 61,889-90.
The Honorable Kimberly D. Bose Secretary November 7, 2008 Page 3 B. Description of LES & Standard of Review LES is a municipal electric utility formed in 1966 that now serves approximately 108,000 residential customers and 15,000 commercial and industrial customers located in Lancaster County, Nebraska, including the cities of Lincoln, Prairie Home, Waverly, Walton, Cheney, and Emerald. LES is a non-profit, customer-owned utility governed by a semi-autonomous administrative board of local citizens. As a political subdivision of the state of Nebraska, LES is not a public utility within the meaning of section 201 of the FPA 6 and is not subject to the Commission s jurisdiction under sections 205 and 206 7 of the FPA. However, the Commission does have jurisdiction under sections 205 and 206 of the FPA over the rates for transmission service provided by SPP, an RTO that is a public utility. In this respect, the courts have made clear that when a non-jurisdictional transmission owner voluntarily joins an RTO, the Commission can ensure by examining [the non-jurisdictional utility s revenue requirement] that the [RTO s] rates will ultimately be just and reasonable. 8 However, the Commission has declined to establish a formal standard of review to be applied to all non-jurisdictional revenue requirement cases. 9 C. Filing in Docket No. ER08-1601-000 On September 30, 2008, SPP filed proposed revisions to its Bylaws, Tariff and Membership Agreements in order to facilitate LES, along with the Nebraska Public Power District ( NPPD ) and Omaha Public Power District ( OPPD ) (collectively Nebraska Entities ), becoming members of SPP. 10 The modifications proposed in the September 30 Filing were designed to accommodate the unique state and local law requirements imposed on NPPD and OPPD as state public power agencies and LES as a municipal electric utility. The September 30 Filing proposed an effective date of December 1, 2008 for the revisions, with the intention that the Nebraska Entities would become members of SPP on December 1, 2008 and transfer control of their transmission 6 7 8 9 10 16 U.S.C. 824(e). 16 U.S.C. 824e. Pac. Gas & Elec. Co. v. FERC, 306 F.3d 1112, 1117 (D.C. Cir. 2002). City of Vernon, Cal., 111 FERC 61,092, at P 36, reh g granted in part and denied in part, 112 FERC 61,207 (2005), reh g denied, 115 FERC 61,297 (2006). Revisions to Bylaws, Tariff and Membership Agreement of Southwest Power Pool, Inc., Docket No. ER08-1601-000 (Sept. 30, 2008) ( September 30 Filing ).
The Honorable Kimberly D. Bose Secretary November 7, 2008 Page 4 systems to SPP and begin participating in SPP s Energy Imbalance Service Market on April 1, 2009. The instant filing is one of several companion filings to integrate each of the Nebraska Entities into SPP as a separate rate zone. 11 II. DESCRIPTION OF THE FILING The instant filing contains LES s proposed formula rate template to be utilized to calculate LES s Annual Transmission Revenue Requirement ( ATRR ) and transmission rates. LES proposes to utilize a formula rate to calculate its ATRR and underlying rates for Network Service and Scheduling and Dispatch Service provided under Schedule 1 of the SPP Tariff. In addition, the formula rate template provides the formula for calculating LES s ATRR for Base Plan Upgrades and other Network Upgrades (Sponsored Upgrades, Service Upgrades and Generation Upgrades) under Attachment J of SPP s Tariff. LES provides both a blank revenue requirement formula rate template and a completed template reflecting data from LES s 2007 Energy Information Administration ( EIA ) Form 412. Although the EIA no longer requires this form to be filed, LES continues to complete the Form 412 annually. The formula rate template proposed by LES is based on a rate template approved for use by non-jurisdictional utilities in the Midwest ISO. The blank and completed formula rate templates are included in Exhibit No. LES-1. The protocol for updating the values in the LES formula rate template, ATRR and underlying transmission rates is included in Exhibit No. LES-2. The formula rate template calculates ATRR by summing transmission Operation and Maintenance ( O&M ) expenses for the transmission facilities being placed under SPP functional control with the transmission allocation of Administrative and General ( A&G ) costs, debt service, taxes and debt coverage (margin). Allocation factors are based on the transmission portion of gross plant or wages and salaries, as appropriate. Adjustments are made to reduce the transmission allocations for transmission facilities not within the SPP footprint. A deduction for Base Plant Funding is included for possible future use. The ATRR is divided by the average annual system demand plus transmission reservations. All values are historic and no true-up will be done. 11 Contemporaneously with this filing, SPP is making three additional filings: (1) an omnibus filing to reflect the necessary tariff revisions to integrate each of the Nebraska Entities as a separate rate zone ( SPP Companion Filing ); (2) a filing on behalf of NPPD to implement its ATRR formula rate template and other documents related to the provision of transmission service in the NPPD Zone; and (3) a filing on behalf of OPPD to implement its ATRR formula rate template and other documents related to the provision of transmission service in the OPPD Zone.
The Honorable Kimberly D. Bose Secretary November 7, 2008 Page 5 The instant filing also includes a rate sheet for Firm and Non-Firm Point-To-Point transmission service within the LES transmission pricing zone in Exhibit No. LES-3. These rates are also included in the SPP Companion Filing as a revision to Attachment T to the SPP Tariff. In addition, the instant filing includes a request for Commission acceptance of LES s transmission loss factor. As indicated in Exhibit No. LES-4, LES s average transmission loss factor is 1.07%. This loss factor is also reflected in the SPP Companion Filing to revise Schedule 1 of Attachment M of its Tariff. Additionally, Exhibit No. LES-5 contains a list of contracts for which LES seeks grandfathered treatment under the SPP Tariff. These contracts have been included in the SPP Companion Filing s revisions to Attachment W of the SPP Tariff. Finally, included in Exhibit No. LES-6 is a list of transmission facilities LES proposes to transfer to SPP s operational control on April 1, 2009. The facilities identified in Exhibit No. LES-6 will form the LES transmission pricing zone in SPP (Zone 16) and are listed in the SPP Companion Filing. LES asserts that all of the facilities identified in Exhibit No. LES-6 comply with the definition of Transmission Facilities set forth in Attachment AI of the SPP Tariff. III. ADDITIONAL INFORMATION A. Waiver and Request for Commission Action On behalf of LES, SPP respectfully requests waiver of the Commission s prior notice requirement, 18 C.F.R. 35.3(a), requiring rates for electric service to be filed no more than 120 days before the rates are scheduled to go into effect. SPP has made the instant filing more than 120 days in advance in order to provide LES with certainty that it will be able to recover its revenue requirements and comply with applicable state laws upon transferring control of its transmission facilities to SPP. The rates proposed herein are scheduled to go into effect on April 1, 2009. Additionally, SPP respectfully requests that the Commission act on the instant filing within 60 days of the date of this filing, in order to ensure that customers have notice of the rates and can make reservations 60 days before the April 1, 2009 effective date and to provide LES with certainty that SPP s transmission service rates will enable it to recover its revenue requirements before it transfers control of its transmission facilities to SPP.
The Honorable Kimberly D. Bose Secretary November 7, 2008 Page 6 B. Information Required by the Commission s Regulations (1) Documents submitted with this filing: In addition to this transmittal letter, the following LES exhibits are included in this filing: Exhibit No. LES-1 Exhibit No. LES-2 Exhibit No. LES-3 Exhibit No. LES-4 Exhibit No. LES-5 Exhibit No. LES-6 LES Revenue Requirement Formula Rate Template Attachment H: Rate Protocol Rate Sheets for Point-to-Point Transmission Service in LES Zone 16 LES Loss Factor List of LES Grandfathered Agreements List of LES Transmission Facilities Comprising Zone 16 (2) Effective date: As discussed above, SPP requests an effective date of April 1, 2009 for the changes proposed in this filing. The requested effective date is intended to coincide with the effective date of the transfer to SPP of functional control over LES s transmission facilities and the addition of the LES Zone to the SPP Tariff. The Tariff revisions for the LES Zone are being submitted separately and contemporaneously with this filing. The addition of the LES Zone to SPP s Tariff is consistent with Commission precedent and in the public interest, and thus warrants the Commission s approval. (3) Service: A copy of this transmittal letter has been served on all SPP members and customers. In addition, a complete copy of this filing has been served on all state commissions within SPP s service region. Finally, a copy of the revised Tariff will be posted on the SPP web page (www.spp.org).
The Honorable Kimberly D. Bose Secretary November 7, 2008 Page 7 (4) Requisite agreements: LES has executed a SPP Membership Agreement, which was included as part of SPP s September 30 Filing in Docket No. ER08-1601-000. (5) Estimate of transactions and revenues: It is not presently possible to make a reasonable prediction of the transactions and revenues resulting from this filing. (6) Basis of rates: The basis for the proposed rates is explained above and in the attached exhibits of LES. (7) Comparison to rates for similar services: The rates proposed herein are for services provided in Zone 16 under the SPP Tariff. Such rates can be compared to the rates for similar services to other zones under the SPP Tariff. (8) Specifically assignable facilities installed or modified: There are none. C. Communications SPP requests that all correspondence and communications with respect to this filing be sent to, and SPP requests that the Secretary include on the official service list, the following: L. Patrick Bourne Director Regulatory Policy Southwest Power Pool, Inc. 415 North McKinley, #140 Plaza West Little Rock, AR 72205 Telephone: (501) 614-3249 Fax: (501) 664-9553 pbourne@spp.org Barry S. Spector Wendy N. Reed Matthew J. Binette WRIGHT & TALISMAN, P.C. 1200 G Street, N.W., Suite 600 Washington, DC 20005-3802 Telephone: (202) 393-1200 Fax: (202) 393-1240 spector@wrightlaw.com reed@wrightlaw.com binette@wrightlaw.com
Exhibit No. LES-1
Based on the Midwest ISO rate template Formula Rate - Cash Flow Rate Formula Template For the 12 months ending 12/31/07 Utilizing EIA Form 412 Data LINCOLN ELECTRIC SYSTEM Line Allocated No. Amount 1 GROSS REVENUE REQUIREMENT (page 2, line 23, col. 5) $ - REVENUE CREDITS (Note Q) Total Allocator 2 Account No. 454 (page 3, line 34) 0 TP 0.00000 0 3 Account No. 456 (page 3, line 37) 0 TP 0.00000 0 4 Revenues from Grandfathered Interzonal Transactions TP 0.00000 0 5 Revenues from service provided by the ISO at a discount TP 0.00000 0 6 TOTAL REVENUE CREDITS (sum lines 2-5) 0 7 NET REVENUE REQUIREMENT for all facilities (line 1 minus line 6) $ - 8 Revenue Requirements for Base Plan Funded Projects 0 9 NET REVENUE REQUIREMENT less base plan funded projects (line 7 minus line 8) $ - DIVISOR 10 Average of 12 coincident system peaks for requirements (RQ) service (Note A) 11 Plus 12 CP of firm bundled sales over one year not in line 10 (Note B) 12 Plus 12 CP of Network Load not in line 10 (Note C) 13 Less 12 CP of firm P-T-P over one year (enter negative) (Note D) 14 Plus Contract Demand of firm P-T-P over one year 15 Less Contract Demand from Grandfathered Interzonal transactions over one year (enter negative) (Note P) 16 Less 12 CP or Contract Demands from service over one year provided by ISO at a discount (enter negative) 17 Divisor (sum lines 10-16) 0 kw 18 Annual Cost ($/kw/yr) (line 9/ line 17) $0.000 19 Network & P-to-P Rate ($/kw/mo) (line 18/ 12) $0.000 Peak Rate Off-Peak Rate 20 Point-To-Point Rate ($/kw/wk) (line 18 / 52; line 18/ 52) $0.000 $0.000 21 Point-To-Point Rate ($/kw/day) (line 20/ 5; line 20/ 7) $0.000 Capped at weekly rate $0.000 22 Point-To-Point Rate ($/MWh) (line 21/ 16; line 21/ 24 $0.000 Capped at weekly $0.000 times 1,000) and daily rates 23 FERC Annual Charge($/MWh) (Note E) $0.000 Short Term $0.000 Short Term 24 $0.000 Long Term $0.000 Long Term 11/6/2008 2:14 PM K:\SPP\Nebraska Joining\Rates\LES FILING\Attachment H Blank Formula Rate Template -- USE THIS VERSION.XLS
Based on the Midwest ISO rate template Formula Rate - Cash Flow Rate Formula Template For the 12 months ending 12/31/07 Utilizing EIA Form 412 Data LINCOLN ELECTRIC SYSTEM (1) (2) (3) (4) (5) Line EIA 412 Transmission No. Reference Company Total Allocator (Col 3 times Col 4) O&M 1 Transmission VII.8.d TE 0.00000 0 2 Less Account 565 1.00000 0 3 A&G VII.13.d W/S 0.00000 0 4 Less FERC Annual Fees W/S 0.00000 0 5 Less EPRI & Reg. Comm. Exp. & Non-safety Ad (Note F) W/S 0.00000 0 5a Plus Transmission Related Reg. Comm. Exp. (Note F) TE 0.00000 0 6 Common CE 0.00000 0 7 Transmission Lease Payments 1.00000 0 8 TOTAL O&M (sum lines 1, 3, 5a, 6, 7 less 2, 4, 5) 0 0 DEBT SERVICE 9 Debt Service GP 0.00000 0 10 Amortization of premium or discount GP 0.00000 0 12 TOTAL DEBT SERVICE (Sum lines 9-10) 0 0 TAXES OTHER THAN INCOME TAXES (Note G) LABOR RELATED 13 Payroll W/S 0.00000 0 14 Highway and vehicle W/S 0.00000 0 15 PLANT RELATED 16 Property GP 0.00000 0 17 Gross Receipts zero 0 18 Other GP 0.00000 0 19 Payments in lieu of taxes GP 0.00000 0 20 TOTAL OTHER TAXES (sum lines 13-19) 0 0 21 SUBTOTAL (sum lines 8, 12, 20) (O&M + DS + Taxes) 0 0 22 MARGIN REQUIREMENT (Note H) GP 0.00000 0 23 REV. REQUIREMENT (sum lines 21, 23) 0 0 11/6/2008 2:14 PM K:\SPP\Nebraska Joining\Rates\LES FILING\Attachment H Blank Formula Rate Template -- USE THIS VERSION.XLS
Based on the Midwest ISO rate template Formula Rate - Cash Flow Rate Formula Template For the 12 months ending 12/31/07 Utilizing EIA Form 412 Data LINCOLN ELECTRIC SYSTEM Line No. SUPPORTING CALCULATIONS AND NOTES EIA 412 GROSS PLANT IN SERVICE Reference Company Total Allocator Transmission 1 Production IV.6.g NA 2 Transmission IV.7.g TP 0.00000 0 3 Distribution IV.8.g NA 4 General & Intangible IV.9.g + IV.1.g W/S 0.00000 0 5 Common CE 0.00000 0 6 TOTAL GROSS PLANT (sum lines 1-5) 0 GP= 0.000% 0 TRANSMISSION PLANT INCLUDED IN ISO RATES 7 Total transmission plant (line 2) 0 8 Less transmission plant excluded from ISO rates (Note J) 9 Less transmission plant included in OATT Ancillary Services (Note K ) 10 Transmission plant included in ISO rates (line 7 less lines 8 & 9) 0 11 Percentage of transmission plant included in ISO Rates (line 10 divided by line 7) TP= 0.00000 TRANSMISSION EXPENSES Schedule 1 Recoverable Expenses 12 Total transmission expenses (page 2, line 1, column 3) 0 13 Less transmission expenses included in OATT Ancillary Services (Note I) 0 Acct 561 included in Line 13? 14 Included transmission expenses (line 12 less line 13) 0 Revenue Credits for Sched 1/Acct 561 transactions <1 yr 15 Percentage of transmission expenses after adjustment (line 14 divided by line 12) 0.00000 non-firm 16 Percentage of transmission plant included in ISO Rates (line 11) TP 0.00000 transactions w/ load not in divisor 17 Percentage of transmission expenses included in ISO Rates (line 15 times line 16) TE= 0.00000 $0 total Revenue Credits $0 Net Schedule 1 Expenses (Acct 561 minus Credits) WAGES & SALARY ALLOCATOR (W&S) (Note L) $ Allocation 18 Production 0.00 0 19 Transmission 0.00 0 20 Distribution 0.00 0 W&S Allocator 21 Other 0.00 0 ($ / Allocation) 22 Total (sum lines 18-21) 0 0 = 0.00000 COMMON PLANT ALLOCATOR (CE) (Note M) $ % Electric Labor Ratio 23 Electric (line 23 / line 26) (line 22) CE 24 Gas 0.00000 * 0.00000 = 0.00000 25 Water 26 Total (sum lines 23-25) 0 FINANCING DATA $ 27 Long Term Debt II.33.b +II.34.b 28 Debt Service 29 Interest on Long Term Debt III.16.b + III.17.b Note R 30 Bond Principal Amortization (line 28 less line 29) 0 REVENUE CREDITS Load ACCOUNT 447 (SALES FOR RESALE) 31 a. Bundled Non-RQ Sales for Resale (Note N) 32 b. Bundled Sales for Resale included in Divisor on page 1 33 Total of (a)-(b) 0 34 ACCOUNT 454 (RENT FROM ELECTRIC PROPERTY) (Note O) ACCOUNT 456 (OTHER ELECTRIC REVENUES) 35 a. Transmission charges for all transmission transactions 36 b. Transmission charges for all transmission transactions included in Divisor on page 1 37 Total of (a)-(b) $0 11/6/2008 2:14 PM K:\SPP\Nebraska Joining\Rates\LES FILING\Attachment H Blank Formula Rate Template -- USE THIS VERSION.XLS
Based on the Midwest ISO rate template Formula Rate - Cash Flow Rate Formula Template For the 12 months ending 12/31/07 Utilizing EIA Form 412 Data LINCOLN ELECTRIC SYSTEM General Note: References to pages in this formulary rate are indicated as: (page#, line#, col.#) References to data from EIA Form 412 are indicated as: x.y.z (section, line, column) To the extent the page references to EIA Form 412 are missing, the entity will include a "Notes" section in Note the EIA Form 412 to provide this data. Letter A The utility's maximum monthly megawatt load (60-minute integration) for RQ service at time of ISO coincident monthly peaks. RQ service is service which the supplier plans to provide on an on-going basis (i.e., the supplier includes projected load for this service in its system resource planning). B Includes LF, IF, LU, IU service. LF means "firm service" (cannot be interrupted for economic reasons and is intended to remain reliable even under adverse conditions), and long-term (duration of at least five years); does not meet definition of RQ service. IF is "firm service" for a term longer than one but less than five years. LU is service from a designated generating unit, of a term no less than five years. LI is service from a designated generating unit for a term between one and five years. Measured at time of ISO coincident monthly peaks. C LF as defined above at time of ISO coincident monthly peaks. D LF as defined above at time of ISO coincident monthly peaks. E The FERC's annual charges for the year assessed the Transmission Owner for service under this tariff, if any F Line 5 - EPRI Annual Membership Dues, all Regulatory Commission Expenses, and non-safety related advertising. Line 5a - Regulatory Commission Expenses directly related to transmission service, ISO filings, or transmission siting. G Includes only FICA, unemployment, highway, property, gross receipts, and other assessments charged in the current year. Taxes related to income are excluded. Gross receipts taxes are not included in transmission revenue requirement in the Rate Formula Template, since they are recovered elsewhere. H The Margin Requirement is the margin the utility uses in calculating rates applicable to its native load sales. The Margin Requirement as a percent of interest expense yields a TIER (times interest earned ratio), and the Margin Requirement as a percent of debt service is the DSR (debt service ratio), either of which may be referred to as a Margin Ratio (MR). Some utilities have MRs required by bond covenants and/or MRs that include expenses additional to interest or debt service (for example, an MR equal to a percentage of the sum of DS+O&M). The ISO will review such party's filings to assure that the MRs are consistent with those applicable to native load or required by bond covenants and utility must provide workpapers showing derivation of margin. I Removes dollar amount of transmission expenses included in the OATT ancillary services rates, including all of Account No. 561. J Removes transmission plant determined by Commission order to be state-jurisdictional according to the seven-factor test (until RUS 12 balances are adjusted to reflect application of seven-factor test). K Removes dollar amount of transmission plant included in the development of OATT ancillary services rates and generation step-up facilities, which are deemed to included in OATT ancillary services. For these purposes, generation step-up facilities are those facilities at a generator substation on which there is no through-flow when the generator is shut down. L If the utility has more employees assigned to A&G than to the sum of production, transmission, and distribution, set the W&S allocator at page 3, line 22 equal to the gross plant allocator (GP) at page 3, line 6. M Enter dollar amounts. N Line 33 must equal zero since all short-term power sales must be unbundled and the transmission component reflected in Account No. 456 and all other uses are to be included in the divisor. O Includes income related only to transmission facilities, such as pole attachments, rentals and special use. P Grandfathered agreements whose rates have been changed to eliminate or mitigate pancaking - the revenues are included in line 4 page 1 and the loads are included in line 13, page 1. Grandfathered agreements whose rates have not been changed to eliminate or mitigate pancaking - the revenues are not included in line 4, page 1 nor are the loads included in line 13, page 1. Q The revenues credited on page 1 lines 2-5 shall include only the amounts received directly (in the case of grandfathered agreements) or from the ISO (for service under this tariff) reflecting the Transmission Owner's integrated transmission facilities. They do not include revenues associated with FERC annual charges, gross receipts taxes, ancillary services, facilities not included in this template (e.g., direct assignment facilities and GSUs) which are not recovered under this Rate Formula Template. R From Reference II.17.b include only the amount from Account 430. 11/6/2008 2:14 PM K:\SPP\Nebraska Joining\Rates\LES FILING\Attachment H Blank Formula Rate Template -- USE THIS VERSION.XLS
Based on the Midwest ISO rate template Formula Rate - Cash Flow Rate Formula Template For the 12 months ending 12/31/07 Utilizing EIA Form 412 Data LINCOLN ELECTRIC SYSTEM Line Allocated No. Amount 1 GROSS REVENUE REQUIREMENT (page 2, line 23, col. 5) $ 12,472,696 REVENUE CREDITS (Note Q) Total Allocator 2 Account No. 454 (page 3, line 34) 246,705 TP 0.67531 166,601 3 Account No. 456 (page 3, line 37) 324,947 TP 0.67531 219,439 4 Revenues from Grandfathered Interzonal Transactions 0 TP 0.67531 0 5 Revenues from service provided by the ISO at a discount 0 TP 0.67531 0 6 TOTAL REVENUE CREDITS (sum lines 2-5) 386,040 7 NET REVENUE REQUIREMENT for all facilities (line 1 minus line 6) $ 12,086,655 8 Revenue Requirements for Base Plan Funded Projects 0 9 NET REVENUE REQUIREMENT less base plan funded projects (line 7 minus line 8) $ 12,086,655 DIVISOR 10 Average of 12 coincident system peaks for requirements (RQ) service (Note A) 584,000 kw 11 Plus 12 CP of firm bundled sales over one year not in line 10 (Note B) 0 kw 12 Plus 12 CP of Network Load not in line 10 (Note C) 0 kw 13 Less 12 CP of firm P-T-P over one year (enter negative) (Note D) 0 kw 14 Plus Contract Demand of firm P-T-P over one year 70,000 kw 15 Less Contract Demand from Grandfathered Interzonal transactions over one year (enter negative) (Note P) 0 kw 16 Less 12 CP or Contract Demands from service over one year provided by ISO at a discount (enter negative) 0 kw 17 Divisor (sum lines 10-16) 654,000 kw 18 Annual Cost ($/kw/yr) (line 9/ line 17) $18.481 19 Network & P-to-P Rate ($/kw/mo) (line 18/ 12) $1.540 Peak Rate Off-Peak Rate 20 Point-To-Point Rate ($/kw/wk) (line 18 / 52; line 18/ 52) $0.355 $0.355 21 Point-To-Point Rate ($/kw/day) (line 20/ 5; line 20/ 7) $0.071 Capped at weekly rate $0.051 22 Point-To-Point Rate ($/MWh) (line 21/ 16; line 21/ 24 $4.443 Capped at weekly $2.116 times 1,000) and daily rates 23 FERC Annual Charge($/MWh) (Note E) $0.000 Short Term $0.000 Short Term 24 $0.000 Long Term $0.000 Long Term 11/6/2008 2:15 PM K:\SPP\Nebraska Joining\Rates\LES FILING\Attachment H Formula With 2007 Data -- USE THIS VERSION.XLS
Based on the Midwest ISO rate template Formula Rate - Cash Flow Rate Formula Template For the 12 months ending 12/31/07 Utilizing EIA Form 412 Data LINCOLN ELECTRIC SYSTEM (1) (2) (3) (4) (5) Line EIA 412 Transmission No. Reference Company Total Allocator (Col 3 times Col 4) O&M 1 Transmission VII.8.d 4,093,662 TE 0.64333 2,633,563 2 Less Account 565 0 1.00000 0 3 A&G VII.13.d 14,434,055 W/S 0.04704 679,011 4 Less FERC Annual Fees 0 W/S 0.04704 0 5 Less EPRI & Reg. Comm. Exp. & Non-safety Ad (Note F) 419,521 W/S 0.04704 19,735 5a Plus Transmission Related Reg. Comm. Exp. (Note F) 0 TE 0.64333 0 6 Common 0 CE 0.04704 0 7 Transmission Lease Payments 0 1.00000 0 8 TOTAL O&M (sum lines 1, 3, 5a, 6, 7 less 2, 4, 5) 18,108,196 3,292,838 DEBT SERVICE 9 Debt Service 42,629,372 GP 0.10452 4,455,722 10 Amortization of premium or discount -495,722 GP 0.10452-51,814 12 TOTAL DEBT SERVICE (Sum lines 9-10) 42,133,650 4,403,908 TAXES OTHER THAN INCOME TAXES (Note G) LABOR RELATED 13 Payroll 2,269,566 W/S 0.04704 106,766 14 Highway and vehicle 11,965 W/S 0.04704 563 15 PLANT RELATED 16 Property 418,947 GP 0.10452 43,789 17 Gross Receipts 0 zero 0 18 Other 0 GP 0.10452 0 19 Payments in lieu of taxes 9,756,156 GP 0.10452 1,019,736 20 TOTAL OTHER TAXES (sum lines 13-19) 12,456,634 1,170,854 21 SUBTOTAL (sum lines 8, 12, 20) (O&M + DS + Taxes) 72,698,480 8,867,601 22 MARGIN REQUIREMENT (Note H) 34,491,137 GP 0.10452 3,605,095 Note this is the "Available for Debt Service" and Debt Service from F&A. Avail. For D.S. $77,120,509 23 REV. REQUIREMENT (sum lines 21, 23) 107,189,617 12,472,696 minus D.S. $42,629,372 $34,491,137 11/6/2008 2:15 PM K:\SPP\Nebraska Joining\Rates\LES FILING\Attachment H Formula With 2007 Data -- USE THIS VERSION.XLS
Based on the Midwest ISO rate template Formula Rate - Cash Flow Rate Formula Template For the 12 months ending 12/31/07 Utilizing EIA Form 412 Data LINCOLN ELECTRIC SYSTEM Line No. SUPPORTING CALCULATIONS AND NOTES EIA 412 GROSS PLANT IN SERVICE Reference Company Total Allocator Transmission 1 Production IV.6.g 559,590,364 NA 2 Transmission IV.7.g 166,374,648 TP 0.67531 112,353,907 3 Distribution IV.8.g 320,716,017 NA 4 General & Intangible IV.9.g + IV.1.g 51,362,873 W/S 0.04704 2,416,226 5 Common 0 CE 0.04704 0 6 TOTAL GROSS PLANT (sum lines 1-5) 1,098,043,902 GP= 10.452% 114,770,133 TRANSMISSION PLANT INCLUDED IN ISO RATES Note: Various Gross Plant Transmission Lines that are excluded from ISO. Walter Scott #4 23,844,092 7 Total transmission plant (line 2) 166,374,648 LRS 24,334,550 8 Less transmission plant excluded from ISO rates (Note J) 54,020,741 LRS - Ault Sub 535,213 9 Less transmission plant included in OATT Ancillary Services (Note K ) 0 LRS West 1,694,724 10 Transmission plant included in ISO rates (line 7 less lines 8 & 9) 112,353,907 Radial Lines 1,967,454 20th & Pioneer to 29th & Leighton 1,644,708 14th & Alvo to NW 12th & Arbor Rd. 11 Percentage of transmission plant included in ISO Rates (line 10 divided by line 7) TP= 0.67531 54,020,741 TRANSMISSION EXPENSES Schedule 1 Recoverable Expenses 12 Total transmission expenses (page 2, line 1, column 3) 4,093,662 13 Less transmission expenses included in OATT Ancillary Services (Note I) 193,859 193,859 Acct 561 included in Line 13? 14 Included transmission expenses (line 12 less line 13) 3,899,803 Revenue Credits for Sched 1/Acct 561 transactions <1 yr 15 Percentage of transmission expenses after adjustment (line 14 divided by line 12) 0.95264 non-firm 16 Percentage of transmission plant included in ISO Rates (line 11) TP 0.67531 transactions w/ load not in divisor 17 Percentage of transmission expenses included in ISO Rates (line 15 times line 16) TE= 0.64333 $0 total Revenue Credits $193,859 Net Schedule 1 Expenses (Acct 561 minus Credits) WAGES & SALARY ALLOCATOR (W&S) (Note L) $ Allocation 18 Production 3,014,623 0.00 0 19 Transmission 1,633,528 0.68 1,103,132 20 Distribution 7,313,978 0.00 0 W&S Allocator 21 Other 11,487,682 0.00 0 ($ / Allocation) 22 Total (sum lines 18-21) 23,449,811 1,103,132 = 0.04704 COMMON PLANT ALLOCATOR (CE) (Note M) $ % Electric Labor Ratio 23 Electric 1,098,043,902 (line 23 / line 26) (line 22) CE 24 Gas 0 1.00000 * 0.04704 = 0.04704 25 Water 0 26 Total (sum lines 23-25) 1,098,043,902 FINANCING DATA $ 27 Long Term Debt II.33.b +II.34.b $691,050,000 28 Debt Service 42,629,372 29 Interest on Long Term Debt III.16.b + III.17.b Note R 31,867,213 30 Bond Principal Amortization (line 28 less line 29) 10,762,159 REVENUE CREDITS Load ACCOUNT 447 (SALES FOR RESALE) 31 a. Bundled Non-RQ Sales for Resale (Note N) 0 32 b. Bundled Sales for Resale included in Divisor on page 1 0 33 Total of (a)-(b) 0 Cell Tower Fees $240,055.20 Wagener Land Rent $3,321.50 34 ACCOUNT 454 (RENT FROM ELECTRIC PROPERTY) (Note O) $246,705 271 Transmission Pole Attachments $3,327.88 $246,704.58 ACCOUNT 456 (OTHER ELECTRIC REVENUES) 35 a. Transmission charges for all transmission transactions $720,391 36 b. Transmission charges for all transmission transactions included in Divisor on page 1 $395,444 37 Total of (a)-(b) $324,947 11/6/2008 2:15 PM K:\SPP\Nebraska Joining\Rates\LES FILING\Attachment H Formula With 2007 Data -- USE THIS VERSION.XLS
Based on the Midwest ISO rate template Formula Rate - Cash Flow Rate Formula Template For the 12 months ending 12/31/07 Utilizing EIA Form 412 Data LINCOLN ELECTRIC SYSTEM General Note: References to pages in this formulary rate are indicated as: (page#, line#, col.#) References to data from EIA Form 412 are indicated as: x.y.z (section, line, column) To the extent the page references to EIA Form 412 are missing, the entity will include a "Notes" section in Note the EIA Form 412 to provide this data. Letter A The utility's maximum monthly megawatt load (60-minute integration) for RQ service at time of ISO coincident monthly peaks. RQ service is service which the supplier plans to provide on an on-going basis (i.e., the supplier includes projected load for this service in its system resource planning). B Includes LF, IF, LU, IU service. LF means "firm service" (cannot be interrupted for economic reasons and is intended to remain reliable even under adverse conditions), and long-term (duration of at least five years); does not meet definition of RQ service. IF is "firm service" for a term longer than one but less than five years. LU is service from a designated generating unit, of a term no less than five years. LI is service from a designated generating unit for a term between one and five years. Measured at time of ISO coincident monthly peaks. C LF as defined above at time of ISO coincident monthly peaks. D LF as defined above at time of ISO coincident monthly peaks. E The FERC's annual charges for the year assessed the Transmission Owner for service under this tariff, if any F Line 5 - EPRI Annual Membership Dues, all Regulatory Commission Expenses, and non-safety related advertising. Line 5a - Regulatory Commission Expenses directly related to transmission service, ISO filings, or transmission siting. G Includes only FICA, unemployment, highway, property, gross receipts, and other assessments charged in the current year. Taxes related to income are excluded. Gross receipts taxes are not included in transmission revenue requirement in the Rate Formula Template, since they are recovered elsewhere. H The Margin Requirement is the margin the utility uses in calculating rates applicable to its native load sales. The Margin Requirement as a percent of interest expense yields a TIER (times interest earned ratio), and the Margin Requirement as a percent of debt service is the DSR (debt service ratio), either of which may be referred to as a Margin Ratio (MR). Some utilities have MRs required by bond covenants and/or MRs that include expenses additional to interest or debt service (for example, an MR equal to a percentage of the sum of DS+O&M). The ISO will review such party's filings to assure that the MRs are consistent with those applicable to native load or required by bond covenants and utility must provide workpapers showing derivation of margin. I Removes dollar amount of transmission expenses included in the OATT ancillary services rates, including all of Account No. 561. J Removes transmission plant determined by Commission order to be state-jurisdictional according to the seven-factor test (until RUS 12 balances are adjusted to reflect application of seven-factor test). K Removes dollar amount of transmission plant included in the development of OATT ancillary services rates and generation step-up facilities, which are deemed to included in OATT ancillary services. For these purposes, generation step-up facilities are those facilities at a generator substation on which there is no through-flow when the generator is shut down. L If the utility has more employees assigned to A&G than to the sum of production, transmission, and distribution, set the W&S allocator at page 3, line 22 equal to the gross plant allocator (GP) at page 3, line 6. M Enter dollar amounts. N Line 33 must equal zero since all short-term power sales must be unbundled and the transmission component reflected in Account No. 456 and all other uses are to be included in the divisor. O Includes income related only to transmission facilities, such as pole attachments, rentals and special use. P Grandfathered agreements whose rates have been changed to eliminate or mitigate pancaking - the revenues are included in line 4 page 1 and the loads are included in line 13, page 1. Grandfathered agreements whose rates have not been changed to eliminate or mitigate pancaking - the revenues are not included in line 4, page 1 nor are the loads included in line 13, page 1. Q The revenues credited on page 1 lines 2-5 shall include only the amounts received directly (in the case of grandfathered agreements) or from the ISO (for service under this tariff) reflecting the Transmission Owner's integrated transmission facilities. They do not include revenues associated with FERC annual charges, gross receipts taxes, ancillary services, facilities not included in this template (e.g., direct assignment facilities and GSUs) which are not recovered under this Rate Formula Template. R From Reference II.17.b include only the amount from Account 430. 11/6/2008 2:15 PM K:\SPP\Nebraska Joining\Rates\LES FILING\Attachment H Formula With 2007 Data -- USE THIS VERSION.XLS
12/31/2007 Scheduling, System Control and Dispatch Service FERC Form 561 $193,859 (Load Dispatch) FERC Form 556 $1,634,466 (System Control & Load Dispatch; SEM) Revenue Requirement $1,828,325 "Divisor" from page 1 Dollars per MW - annually Dollars per MW - monthly 654,000 kw $296.42 per MW-Annually $24.70 per MW-Monthly K:\SPP\Nebraska Joining\Rates\LES FILING\Attachment H Formula With 2007 Data -- USE THIS VERSION.XLS 11/6/2008
Exhibit No. LES-2
Lincoln Electric System Attachment H For the Lincoln Electric System (LES), the annual transmission revenue requirement for purposes of Network Integration Transmission Service, Base Plan Upgrades, Scheduling, System Control and Dispatch Service, and for the determination of Point-to-Point rates shall be calculated using the Formula Rate Template set forth in Attachment H Addendum 6 of this Tariff. The annual transmission revenue requirement and rates calculated pursuant to the formula rate template shall be revised annually. The results of such annual calculations shall be posted on LES OASIS website and in a publicly accessible location on the Transmission Provider s website by May 15 of each calendar year. Written comments will be accepted until June 15 and the annual revenue requirement and rates shall become effective from August 1 of such year through July 31 of the following year. Supporting data for completion of the formula rate template will be available from LES upon request. Initially, the rates calculated pursuant to the formula-based rate template and incorporated into this SPP OATT will be in place through July 31, 2009. LES Attachment H.doc
Exhibit No. LES-3
Lincoln Electric System Rate Sheet For Point-to-Point Transmission Service Firm Point-To-Point Transmission Service The Transmission Customer shall compensate the Transmission Provider each month for Firm Point-To-Point Transmission Service up to the sum of the applicable charges set forth below: 1. Yearly delivery: one-twelfth of the demand charge of $18.481/kW of Reserved Capacity per year. 2. Monthly delivery: $1.540/kW of Reserved Capacity per month. 3. Weekly delivery: $0.355/kW of Reserved Capacity per week. 4. Daily delivery: On-Peak: $0.071/kW of Reserved Capacity per day. Off-Peak: $0.051/kW of Reserved Capacity per day. On-Peak is all hours between HE 0700 and HE 2200, inclusive, Central Time Zone, excluding Sundays and holidays. Holidays shall be as defined by NERC, currently New Year's Day, Memorial Day, Independence Day, Labor Day, Thanksgiving Day, and Christmas Day. Off-Peak is all hours not designated as On-Peak. The total demand charged in any week, pursuant to a reservation for Daily delivery, shall not exceed the rate specified in section (3) above times the highest amount in kilowatts of Reserved Capacity in any day during such week.
Non-Firm Point-To-Point Transmission Service The Transmission Customer shall compensate the Transmission Provider each month for Non-Firm Point-To-Point Transmission Service up to the sum of the applicable charges set forth below: 1. Monthly delivery: $1.540/kW of Reserved Capacity per month. 2. Weekly delivery: $0.355/kW of Reserved Capacity per week. 3. Daily delivery: On-Peak: $0.071/kW of Reserved Capacity per day. Off-Peak: $0.051/kW of Reserved Capacity per day. 4. Hourly delivery: On-Peak: $4.443/MWh of Reserved Capacity per hour. Off-Peak: $2.116/MWh of Reserved Capacity per week. On-Peak is all hours between HE 0700 and HE 2200, inclusive, Central Time Zone excluding Sundays and holidays. Holidays shall be as defined by NERC, currently New Year's Day, Memorial Day, Independence Day, Labor Day, Thanksgiving Day, and Christmas Day. Off-Peak is all hours not designated as On-Peak. The total demand charge in any day, pursuant to a reservation for Hourly delivery, shall not exceed the rate specified in section (3) above times the highest amount in kilowatts of Reserved Capacity in any hour during such day. In addition, the total demand charge in any week, pursuant to a reservation for Hourly or Daily delivery, shall not exceed the rate specified in section (2) above times the highest amount in kilowatts of Reserved Capacity in any hour during such week.
Exhibit No. LES-4
LES Transmission System Losses 9/22/2008 LES TRANSMISSION LOSSES FOR 2009 Prepared by Resource & Transmission Planning Department Lincoln Electric System September 2008 1
LES Transmission System Losses 9/22/2008 Table of Contents 1.0 Executive Summary... 3 2.0 Introduction... 4 2.1 General Information... 4 2.2 Scope... 5 3.0 Study Procedure... 5 3.1 Computer Programs... 5 3.2 Model Development... 5 3.3 Methodology... 5 4.0 Tabulation of Transmission Losses... 7 5.0 Conclusion and Recommendation... 11 2
LES Transmission System Losses 9/22/2008 1.0 Executive Summary In order to give a Balancing Area (BA) Transmission system loss factor to SPP, it was determined that LES needed to update our loss analysis to compute this correctly. The LES transmission system is a relatively compact system, meaning shorter lines and probably lower losses than our neighbors. It is made up of 345kV, 161kV and 115kV facilities. All of LES base load resources (511MW) are external to LES BA but there is over 450MW of internal generation. LES 2009 inlet load forecast is 774MW. This study looked at 2009 and 2010 and determined transmission system losses for multiple load points throughout the two years and losses with and without internal generation. After completing the analysis documented in this report it is recommended that LES utilize a 1.07% loss factor for 2009. Since this study did show a significant drop in losses for 2010 it is also recommended that LES repeat a loss analysis for 2010 in the last quarter of 2009. 3
LES Transmission System Losses 9/22/2008 2.0 Introduction 2.1 General Information The Lincoln Electric System (LES) transmission system is fairly compact serving primarily the City of Lincoln Nebraska but does serve some small communities in the immediate area. All load is considered to be load of LES and as such LES has not historically metered data coming off of the transmission system separately. The transmission system consists of a combination of 345, 161 and 115kV facilties. LES major inlets are at 345kV although there is one 161kv inlet and four 115kV inlets. Beginning in 2009 LES will have a 345kV loop around the service territory. Off of this loop there are two interconnections to OPPD and two to NPPD. During 2009, so that by 2010, there will be a new 345kV interconnection to NPPD that will be completed. There are three LES 345/115kV transformers and one 161/115kv transformer owned by LES. The LES transmission system is connected to the LES distribution system primarily by 115/12.5kV transformers although there is some 115/34.5kV transformers as well. LES base load resources are external to LES service territory and balancing area. Internal to LES service territory LES owns the following natural gas fired (or oil fired backup) resources: Peak Capacity Unit Rating Rokeby #1 74 Rokeby #2 88 Rokeby #3 94 Rokeby BS 3.2 J Street 30 SVGS #1 27.5 2 on 1 CC Operation SVGS #2 46 SVGS #3 46 SVGS #4 46 SVGS BS 1.75 456.45 All of these units except J Street are stepped up to 115kV. These units would be used when the LES load exceeds our base load capability of 511MW (effective 2009). The Black Start (BS) units are not generally used to serve load and are only oil fired. The LES Summer peak load is forecast to be 774MW in 2009 and 789 in 2010. (This is defined as the net interchange plus LES internal generation). 4
LES Transmission System Losses 9/22/2008 2.2 Scope There are several reasons for LES to review our transmission loss calculations: Many changes to 345kv system Moving to SPP requires that we have a Transmission system loss number A transmission loss number alone did not mean much to LES when all load in LES is defined as LES load. Since LES does not have metering to determine losses directly from the transmission system the losses will have to be calculated based on a power flow analysis of the system. To determine the appropriate loss figure two years (2009 and 2010) will be looked at due to the addition of the NPPD 345kV interconnection prior to 2010 and incorporated in the 2010 MRO transmission system models. Multiple load levels will be investigated to represent 4 seasons in each of the years. Finally the impact of LES internal generation on our losses will also be investigated. After this analysis the most appropriate loss value will be identified for the LES transmission system.. 3.0 Study Procedure 3.1 Computer Programs The PSS/E Power System Simulator, Version 30.3 was used to calculate the transmission losses for this report. 3.2 Model Development The preliminary MRO 2008 Series models (Pass 5) were used to calculate the transmission losses used in this study and report. The only changes made to these models are described in the following section on the study methodology. 3.3 Methodology The system load forecast for the years 2009 and 2010 that was used to calculate the LES transmission losses are included in the following two tables (note the hours are based on 52 week year so there 8,736 hours in 52 weeks): 5
LES Transmission System Losses 9/22/2008 Table I: Year = 2009 Month Peak Energy Hours % weight (MW) (MWH) Jan-Mar 534 875,454 2,184 25.0% Apr-May 577 525,681 1,464 16.8% Jun-Sep 774 1,346,329 2,928 33.5% Oct-Dec 549 831,958 2,160 24.7% Annual 774 3,579,422 8,736 100.0% Table II: Year = 2010 Month Peak Energy Hours % weight (MW) (MWH) Jan-Mar 544 893,865 2,184 25.0% Apr-May 594 540,209 1,464 16.8% Jun-Sep 789 1,384,263 2,928 33.5% Oct-Dec 558 852,757 2,160 24.7% Annual 789 3,671,094 8,736 100.0% The 2009 power flow models were mapped to the load forecast as shown below. The 2010 power flow models used the same mapping. 2009 Spring Peak Use Apr-Mar load level 2009 Summer Peak Use Jun-Sep load level 2009 Fall Peak Use Oct-Dec load level 2009 Winter Peak Use Jan-Mar load level The following steps were used to calculate the transmission losses: Step 1 Set the local gas-fired generation to the desired real and reactive power output, and let the shift in generation be off-set against the system swing bus generation. Step 2 Scale the load so the sum of load plus losses match the forecasted load highlighted in Tables I and II. Step 3 The transmission losses were determined by adding power flows at the system inlet points to the net local generation (inside BA), and then summing and subtracting the power flowing into the high voltage side of the 115/35kV and 6
LES Transmission System Losses 9/22/2008 115/12kV transformers. The remainder is the transmission losses. See Tables V and VI for the detailed results. 4.0 Tabulation of Transmission Losses Tables III and IV summarize the transmission losses. Tables V and VI show results from the eight power flow cases (Spring, Summer, Fall, and Winter) for the combined years 2009 and 2010. Table III takes the data from Table V and shows two different loss calculations depending on how the local system generation is handled. It boils down to what is used for the denominator for the transmission system load. So the loss percentages are calculating using two different definitions for transmission system load. For the column title Load as the basis for the loss percentage, the denominator is Forecast load (or inlet load) minus losses. For the column titles Net Load as the basis for the loss percentage, the denominator is the Forecast Load minus internal generation or Net load minus losses. Table III - Local Gas-Fired Generation on line 2009 2010 Loss Percentage based on Loss Percentage based on Season Forecast load Net Load Losses Load Net load Forecast load Net Load Losses Load Net load Spring 577 479 4.6 0.80% 0.97% 594 479 4.4 0.75% 0.93% Summer 774 550 7.3 0.95% 1.35% 789 550 6.7 0.86% 1.23% Fall 549 482 4.8 0.88% 1.01% 558 482 4.1 0.74% 0.86% Winter 534 479 4.6 0.87% 0.97% 544 479 5.3 0.98% 1.12% weighted annual 0.89% 1.10% 0.84% 1.06% The two different calculations are presented because technically neither is quite correct. When local gas-fired generation is brought on line for LES that generation is an input onto the 115kV system, which effectively unloads the 345kV. However it does not unload the 115kV system. So the losses are probably somewhere between the two numbers calculated for each year. 7
LES Transmission System Losses 9/22/2008 Table IV takes the data from Table VI and calculates the loss percentage based on serving the LES entire load thru our transmission system (i.e. no internal generation on to meet the same inlet load requirement, or Load forecast). Table IV Local Gas-Fired Generation OFF line 2009 2010 Season Forecast load Losses Loss Percentage Forecast load Losses Loss Percentage Spring 577 5.0 0.87% 594 4.9 0.83% Summer 774 9.7 1.27% 789 8.7 1.11% Fall 549 5.5 1.01% 558 4.5 0.81% Winter 534 5.2 0.98% 544 5.6 1.04% weighted annual 1.07% 0.97% This is a method where we know that the denominator is correct because all load is delivered thru the transmission system in this case. The results from these cases do indeed give results between the two calculations utilized in Table III. So while this method is utilized for it s mathematical simplicity and correctness and may not represent how internal generation is handled to generally serve load it is believed to be the calculation that yields the best Loss percentage calculation. Table V calculates transmission losses for the conditions with local gas-fired generation on line to serve load, and Table VI for the conditions with local gas-fired generation off line. For example, the Spring case in Table V resulted in a power flow at the system meters totaling 479 MW, net generation of 98 MW, when combined together yielded a 577 inlet load and a total transmission system load of 572.4 MW. The calculated transmission losses were 4.6 MW. 8