BEFORE THE NEW MEXICO PUBLIC REGULATION COMMISSION ) ) ) ) ) ) ) ) ) ) ) DIRECT TESTIMONY WILLIAM A. GRANT. on behalf of

Transcription

1 BEFORE THE NEW MEXICO PUBLIC REGULATION COMMISSION IN THE MATTER OF SOUTHWESTERN PUBLIC SERVICE COMPANY S APPLICATION FOR REVISION OF ITS RETAIL RATES UNDER ADVICE NOTICE NO., SOUTHWESTERN PUBLIC SERVICE COMPANY, APPLICANT. ) ) ) ) ) ) ) ) ) ) ) CASE NO. -00-UT DIRECT TESTIMONY WILLIAM A. GRANT on behalf SOUTHWESTERN PUBLIC SERVICE COMPANY

2 TABLE OF CONTENTS GLOSSARY OF ACRONYMS AND DEFINED TERMS... iii LIST OF ATTACHMENTS... vi I. WITNESS IDENTIFICATION AND QUALIFICATIONS... II. ASSIGNMENT AND SUMMARY OF TESTIMONY AND RECOMMENDATIONS... III. SOUTHWEST POWER POOL SERVICES... A. RELIABILITY COORDINATION... B. TARIFF ADMINISTRATION AND REGIONAL SCHEDULING... C. TRANSMISSION EXPANSION PLANNING.... TRANSMISSION PLANNING PROCESS.... SPP COST ALLOCATION FOR NEW TRANSMISSION INFRASTRUCTURE.... SPP DIRECTIVES TO CONSTRUCT FACILITIES.... SPP EXPANSION.... ATTACHMENT Z... D. MARKET OPERATIONS... IV. SPP ADMINISTRATIVE FEE... VERIFICATION... ii

3 GLOSSARY OF ACRONYMS AND DEFINED TERMS Acronym/Defined Term APC ARR ATP ATRR B/C Basin Electric CAWG Commission DTO EIS ESWG FERC Heartland ITP ITP0 ITP0 ITPNT kv LMP MOPC Meaning Adjusted Production Cost Auction Revenue Rights Authorization to Plan Annual Transmission Revenue Requirement Benefit-to-Cost Basin Electric Power Cooperative Cost Allocation Working Group New Mexico Public Regulation Commission Designated Transmission Owner Energy Imbalance Service Economic Studies Working Group Federal Energy Regulatory Commission Heartland Consumers Power District Integrated Transmission Planning SPP 0 Year assessment transmission needs SPP 0 Year assessment transmission needs SPP Near Term assessment transmission needs Kilovolt Locational Marginal Price Markets and Operations Policy Committee iii

4 Acronym/Defined Term MTF MWG MWh NERC NITS NTC O&M OATT Operating Companies PUCT RC RCAR RFP RSC RTO RTWG RUC SPP SPP Tariff SPS Meaning Metrics Task Force Market Working Group Megawatt-hour North American Electric Reliability Corporation Network Integration Transmission Service Notification to Construct Operation and Maintenance Open Access Transmission Tariff Northern States Power Company, a Minnesota corporation; Northern States Power Company, a Wisconsin corporation; Public Service Company Colorado, a Colorado corporation; and SPS Public Utility Commission Texas Reliability Coordinator Regional Cost Allocation Review Request for Proposal Regional State Committee Regional Transmission Organization Regional Tariff Working Group Reliability Unit Commitment Southwest Power Pool Open Access Transmission Tariff Southwestern Public Service Company, a New Mexico corporation iv

5 Acronym/Defined Term TCR Meaning Transmission Congestion Rights Test Year July, 0 through June 0, 0 TO TWG WAPA Xcel Energy XES Transmission Owner Transmission Working Group Western Area Power Administration Xcel Energy Inc. Xcel Energy Services Inc. v

6 LIST OF ATTACHMENTS Attachment Description WAG- SPP Organizational Chart 0 (Filename: WAG-.pdf) WAG- Summary Southwest Power Pool s Cost Allocation Methods (Filename: WAG-.pdf) vi

7 Case No. -00-UT I. WITNESS IDENTIFICATION AND QUALIFICATIONS 0 Q. Please state your name and business address. A. My name is. My business address is 00 South Tyler, Suite 00, Amarillo, Texas 0. Q. On whose behalf are you testifying in this proceeding? A. I am filing testimony on behalf Southwestern Public Service Company, a New Mexico corporation ( SPS ) and wholly-owned electric utility subsidiary Xcel Energy Inc. ( Xcel Energy ). Xcel Energy is a utility holding company that owns several electric and natural gas utility operating companies, a regulated natural gas pipeline company, and three electric transmission companies. Q. By whom are you employed and in what position? A. I am employed by SPS, as Director, Strategic Planning. Xcel Energy is the parent company four utility operating companies: Northern States Power Company, a Minnesota corporation; Northern States Power Company, a Wisconsin corporation; Public Service Company Colorado, a Colorado corporation; and SPS (collectively, Operating Companies ). Xcel Energy s natural gas pipeline subsidiary is WestGas InterState, Inc. Through a subsidiary, Xcel Energy Transmission Holding Company, LLC, Xcel Energy also owns three transmission-only operating companies, Xcel Energy Southwest Transmission Company, LLC, Xcel Energy Transmission Development Company, LLC, and Xcel Energy West Transmission Company, LLC, all which are either currently regulated by the Federal Energy Regulatory Commission ( FERC ) or expected to be regulated by FERC.

8 Case No. -00-UT 0 Q. Please briefly outline your responsibilities as Director, Strategic Planning. A. I am responsible for determining the appropriate planning strategy for SPS. In this role, I work with generation and transmission planning and coordinate with the Southwest Power Pool ( SPP ) on regional policy and cost allocation issues affecting SPS. Q. Please describe your pressional experience. A. I have over 0 years experience in both power plant and system operations at Xcel Energy or its predecessors. For seven years, I was Director, Power Operations for Xcel Energy Services Inc. ( XES ), in which I was responsible for the economic dispatch and analytical support for all the Xcel Energy Operating Companies, including SPS. For seven years, I was Manager, Transmission Control Center and Wind Integration for SPS. In 0, I was named Director, Strategic Planning for SPS. Q. Have you testified before any regulatory authorities? A. Yes. I have testified before the New Mexico Public Regulation Commission ( Commission ), the Public Utility Commission Texas ( PUCT ), the Colorado Public Utilities Commission, and the FERC.

9 Case No. -00-UT II. ASSIGNMENT AND SUMMARY OF TESTIMONY AND RECOMMENDATIONS Q. What is your assignment in this proceeding? A. In this proceeding, I: provide a general overview SPP and the benefits SPS s membership in SPP provides to customers; address how SPP is a member-driven regional transmission organization ( RTO ) governed through various committees and stakeholder groups that lead to major initiatives to improve or enhance SPP operations; 0 discuss the services SPP provides to SPS, such as: reliability coordination; tariff administration; regional scheduling; transmission expansion planning; market operation; contingency reserve sharing; generation interconnection studies; scheduling authority function; compliance; training; and outage coordination; 0 address the transmission expansion planning processes SPP, including examples how SPS undertakes actions to ensure the resulting transmission expansion projects are reasonable and necessary, and how the costs transmission expansion projects are allocated among SPP s members; describe how SPS s share the regional and zonal transmission expansion projects costs are recovered through Schedule charges assessed by SPP, SPS s estimate these charges in the future, and the benefits SPS receives from these transmission expansion projects; as part my discussion the cost recovery for transmission expansion projects, provide background regarding the back-billed charges associated with Attachment Z and explain that SPS should be allowed to recover those charges in this case;

10 Case No. -00-UT discuss the SPP Integrated Marketplace, which replaced the former Energy Imbalance Service ( EIS ) Market on March, 0; and discuss the SPP administrative fee. 0 Q. Please summarize the conclusions and recommendations in your testimony. A. The SPP is a FERC-approved RTO that provides a number vital services and functions for SPS and other members, including reliability coordination, transmission planning, and market operation. In addition, the SPP is a member-driven RTO governed through various committees and stakeholder groups that develop major initiatives to improve or enhance SPP operations. As a result the stakeholder initiatives and through its FERC-approved tariff, the SPP provides many vital services to SPS, such as: reliability coordination; tariff administration; regional scheduling; transmission expansion planning; market operation; contingency reserve sharing; generation interconnection studies; scheduling authority function; compliance; training; and outage coordination. SPS customers have not only benefited through greater reliability as a result SPS s membership in the SPP, but through production cost and operation and maintenance ( O&M ) savings. On March, 0, the SPP Integrated Marketplace commenced operation. The Integrated Marketplace is superior to the prior EIS Market in that, among

11 Case No. -00-UT 0 other items, the Integrated Marketplace includes a Day-Ahead Market, through which SPP uses a co-optimization algorithm to clear, dispatch, and price energy and operating reserves. This process minimizes overall costs and provides incremental benefits to SPS customers. SPP administers the cost allocations and collects the revenue for regional and zonal transmission expansion projects through Schedule charges. SPP assesses Schedule charges to each Transmission Owner ( TO ) based on each project s approved allocation method. Accordingly, SPS pays for a portion regional and zonal transmission expansion projects through Schedule charges, but also receives Schedule revenues for SPS s own projects from transmission customers in other areas the SPP footprint. In exchange for the services and benefits SPP provides to SPS, it assesses SPS and other transmission owners an administrative fee. The fee is assessed based upon transmission services purchased or provided under the SPP Open Access Transmission Tariff ( OATT or SPP Tariff ). The SPP Board Directors has indicated that the 0 Administrative Fee will be $0. per megawatt hour ( MWh ). The 0 Administrative Fee is reflected in the cost service study presented by SPS witness Arthur P. Freitas.

12 Case No. -00-UT In light the benefits SPP has provided, and continues to provide, to SPS customers, it is reasonable for the Commission to authorize SPS to recover its SPP-related costs in base rates, including the back-billed charges associated with Attachment Z. Q. Are Attachments WAG- and WAG- true and correct copies the documents you have described in your testimony? A. Yes. The SPP prepared both these documents, which I have reviewed and believe to be accurate.

13 Case No. -00-UT III. SOUTHWEST POWER POOL SERVICES Q. Please describe the SPP and the services it provides to its members. A. SPP is a FERC-approved RTO. It is an Arkansas non-prit corporation with its principle place business in Little Rock, Arkansas. SPP has more than members that include electric cooperatives, federal agencies, independent power producers, independent electric transmission companies, investor-owned electric utilities, marketers, municipal utilities, state authorities, and contract participants. As an RTO, SPP provides several services to its members, including: 0 reliability coordination; tariff administration; regional scheduling; transmission expansion planning; market operation; contingency reserve sharing; generation interconnection studies; scheduling authority function; compliance; training; and outage coordination.

14 Case No. -00-UT 0 Q. How are SPP s policies, rules, and tariffs developed? A. SPP is a member-driven organization. As a result, various committees exist to develop policy, rules, and tariff provisions related to a wide variety topics. The primary role SPP stakeholder committees and working groups is to drive major initiatives that improve or enhance SPP operations. The stakeholder process also focuses on planning for the future. The various committees and working groups provide recommendations to the SPP independent Board Directors on technical issues. The committees are further comprised working groups, steering committees, and task forces. The committees and groups are made up representatives SPP members, including SPS. An organizational chart SPP s committees and working groups is attached to my testimony as Attachment WAG -. Q. Please provide an explanation the SPP s committee and working group structure. A. The SPP Board Directors is the ultimate decision-maker for the SPP, but various sub-groups report directly to the SPP Board. One group is the Market and Operations Policy Committee ( MOPC ). The MOPC has representatives from all SPP members and is responsible for making recommendations to the Board

15 Case No. -00-UT 0 Directors involving market, policy, planning, and operational issues. The proposals provided by the MOPC reflect input and work a number subgroups, including the Transmission Working Group ( TWG ), the Market Working Group ( MWG ), and the Regional Tariff Working Group ( RTWG ). I am the voting member on the MOPC for SPS. The TWG is responsible for planning criteria to evaluate transmission additions, seasonal Available Transmission Capacity calculations, seasonal flowgate ratings, oversight coordinated planning efforts, and oversight transmission contingency evaluations. The TWG develops recommendations for the MOPC regarding changes to particular sections the SPP s Reliability Criteria and works with individual transmission owners on issues coordinated planning and North American Electric Reliability Corporation ( NERC ) and SPP compliance. The TWG is also responsible for publication seasonal and future reliability assessment studies on the transmission system the SPP region. The MWG is responsible for the development and coordination the changes necessary to support any SPP administered wholesale market(s), including energy, congestion management, and market monitoring. The RTWG is responsible for development, recommendation, overall implementation, and

16 Case No. -00-UT oversight SPP s OATT. The RTWG further advises the SPP staff on 0 regulatory or implementation issues not specifically covered by the SPP Tariff or issues where there may be conflict or differing interpretations the SPP Tariff. Q. Do state retail rate regulators have a role in the SPP member-driven process? A. Yes. State retail regulators in the SPP footprint, including this Commission, have an active role through the Regional State Committee ( RSC ). Q. What is the RSC? A. The RSC is comprised retail regulators across the SPP footprint and has its own working group, the Cost Allocation Working Group ( CAWG ), which is made up staff members the retail regulatory authorities. The SPP RSC actively engages in a broad range issues where the SPP has ceded authority, including transmission planning and cost allocation, resource adequacy, allocation transmission rights, and market evolution issues. For example, the RSC determines: () the approach for resource adequacy across the entire region and with respect to transmission planning; () whether transmission upgrades for remote resources will be included in the regional transmission planning process; 0

17 Case No. -00-UT 0 and () the role transmission owners in proposing transmission upgrades in the regional planning process. The SPP RSC may further direct the SPP to submit FERC filings to effectuate regional changes proposed by the SPP RSC. Thus, the RSC is an active and important part the SPP stakeholder process, providing collective retail regulatory agency input on matters regional importance related to the development and operation the bulk electric transmission system. Q. Does SPS participate in the SPP committees and working groups? A. Yes. SPS and XES employees participate at SPP in various committees and working groups. As noted above, I am currently a member MOPC and the Strategic Planning Committee. Another example is SPS witness Kenneth R. Munsell, who is a member SPP s Minimum Design Standards Task Force as well as the Project Cost Working Group. A. Reliability Coordination Q. Please discuss the SPP s reliability coordination function. A. NERC standards require every Regional Reliability Organization, sub-region, or interregional coordinating group to establish a Reliability Coordinator ( RC ) to continually assess transmission reliability and coordinate emergency operations among the operating entities within the region and across the regional boundaries.

18 Case No. -00-UT 0 The SPP is recognized as the RC for all the SPP Transmission Operators. The SPP RC is responsible for the bulk transmission reliability and power supply reliability within its Reliability Coordination Area. Bulk transmission reliability functions include assessment real-time, current day, and next-day operating conditions, loading relief procedures, re-dispatch generation, coordination transmission and generation outages, and ordering curtailment transactions and load. Power supply reliability activities entail monitoring Balancing Authority Area performance and ordering corrective actions, including load curtailment and adjusting generation levels in situations where an imbalance between generation and load places the system in jeopardy. B. Tariff Administration and Regional Scheduling Q. Please discuss the SPP s Tariff Administration and Regional Scheduling functions. A. The SPP Tariff prescribes non-discriminatory rates, terms, and conditions for market participants within the SPP to transport power. The SPP administers that tariff by processing requests for transmission service and making sure that the transmission paths are not overloaded. The SPP also acts as the settlement agent by collecting revenue from the entities who request transmission service and

19 Case No. -00-UT 0 forwarding the appropriate amount that revenue to the owners the transmission facilities. In its role as tariff administrator, the SPP also follows other stakeholder-approved documents such as the SPP Market Protocols and the SPP Business Practices. The SPP requires that load-serving entities provide plans showing how much energy they expect to withdraw from the grid in a given hour. The SPP also requires generation resources to submit plans showing how much energy they anticipate injecting onto the grid in a particular hour. The SPP is responsible for ensuring that the amount energy that is delivered to the grid is matched with the amount that is needed to serve load. SPP s regional scheduling service reduces the number entities with which SPP members and customers have to coordinate. C. Transmission Expansion Planning. Transmission Planning Process Q. Please discuss the SPP s Transmission Planning function. A. As a FERC-designated RTO, one SPP s responsibilities is to create regional transmission expansion plans. With its members, regulators, and stakeholders, SPP creates planning models and studies that determine what and when new

20 Case No. -00-UT 0 transmission is needed to meet the region's long- and near-term needs. This planning activity creates a cost-effective, flexible, and robust transmission network. Q. Please provide a brief history the SPP regional transmission planning process. A. Before 00, the transmission owning companies in the SPP footprint coordinated with SPP on projects that were needed for the reliability the local areas being served. Q. What changed in 00? A. The SPP, with RSC participation, approved the SPP Transmission Expansion Plan, which encouraged transmission expansion for reliability purposes utilizing region-wide cost sharing. Q. Why did SPP members, with RSC participation, decide to change to this region-wide cost sharing methodology? A. The SPP members, as well as the RSC committee, recognized that the transmission expansion process alone would not encourage the build out transmission that was needed to recognize economic benefits. The stakeholders recognized that there were several projects that would have large economic

21 Case No. -00-UT 0 benefits that fell just short being justified solely on the reliability criteria. That is not to say that these projects would not add reliability benefits, but that they were not justified on the criteria at that time. Q. What was the next step in the progression regional transmission planning? A. While the stakeholders were working on a regional planning process that would include cost allocation on a regional basis, the stakeholders also recognized that there were several projects that would add immediate benefits to the region. The stakeholders identified several projects and developed what was called the Balanced Portfolio. Q. What is the Balanced Portfolio? A. The Balanced Portfolio is an SPP strategic initiative to develop a cohesive grouping economic transmission upgrades that benefit the SPP region and allocates the cost those upgrades regionally. Projects in the Balanced Portfolio include upgrades kilovolt ( kv ) transmission facilities that are intended to reduce congestion on the SPP transmission system, thus resulting in savings in generation production costs. These economic upgrades may provide other benefits to the power grid, such as increasing reliability and lowering required reserve margins, deferring reliability upgrades, and providing environmental

22 Case No. -00-UT 0 benefits due to more efficient operation assets and greater utilization renewable resources. The portfolio projects approved by the SPP Board Directors is designated as the Portfolio E Adjusted. Q. What was the next step in the evolution the SPP transmission planning process? A. Through the regional planning process and Balanced Portfolio, the SPP stakeholders transitioned to a process that took into account both reliability and economic benefits using an expanded cost allocation methodology to ensure those who benefit would also pay a reasonable portion the costs. While this new allocation methodology was being approved, another set projects was identified that would provide immediate benefits to the region. These were projects that were showing up on many future planning scenarios that also added immediate economic benefits. This set projects was called the priority projects. The priority projects were the first set transmission projects whose costs were allocated based on the Highway/Byway methodology approved by SPP and FERC in 00, which I discuss in further detail below. SPP then transitioned into the current process that is utilized today.

23 Case No. -00-UT 0 Q. Please summarize the process SPP uses for transmission expansion planning. A. As outlined in Attachment O the SPP OATT, SPP uses an integrated transmission planning ( ITP ) process, which is an iterative three-year process that includes 0-year, 0-year, and near-term assessments transmission needs. The ITP process focuses on regional needs and positions SPP to prepare for and quickly respond to national energy priorities. A major objective the ITP process is the design and construction a transmission backbone to connect load centers to known or expected large generation resources. The process seeks to target a reasonable balance between long-term transmission investment and congestion costs to customers. The ITP process also integrates several existing SPP transmission planning processes, including: () transmission service requests; () generation interconnection service requests; () the 0 Year assessment ( ITP0 ); () the 0 Year assessment ( ITP0 ); () the Near Term assessment ( ITPNT ); () the Balanced Portfolio; () High Priority Upgrades; () Sponsored Upgrades; and () Interregional Projects. Q. What is a transmission service request? A. Those entities who wish to obtain transmission service on the SPP transmission system must complete applications through the SPP Open Access Same-Time

24 Case No. -00-UT 0 Information System. SPP performs studies in aggregate with other completed applications to determine whether the requests can be accommodated and what, if any, additions, modifications, and upgrades to the SPP transmission system are needed to approve the requests. Q. What is a generation interconnection request? A. This is a request made to connect a generating unit to the SPP transmission system or increase the capacity a generating unit that is connected to the SPP transmission system. Standard procedures exist for SPP to evaluate these requests, including the assignment costs for additions, modifications, and upgrades to the SPP transmission system to allow the generator to interconnect. Q. What is the ITP0? A. The ITP0 identifies the transmission projects planned to be constructed over a 0-year period, generally above 00-kV, and provides a grid flexible enough to provide benefits to the region under different potential load growth and transmission usage patterns. Q. What is the ITP0? A. The ITP0 is a planning approach that analyzes the transmission system for a 0-year horizon, and considers both system reliability and the economics new

25 Case No. -00-UT 0 facilities. The assessment will identify 00-kV and above solutions for issues identified on the -kv and above system, as well as issues identified by the ITP0 process appropriate for the ITP0 study. The ITP0 has a narrower focus than the ITP0. Economic and reliability analyses are utilized to help eliminate or prevent potential violations NERC and SPP reliability standards, mitigate congestion, improve access to markets, improve interconnections, and establish the timing projects identified in the ITP0. Q. What is the ITPNT? A. The ITPNT is performed annually and assesses the system requirements and upgrades at all applicable voltage levels required in the near-term planning horizon (generally, for the next one to five years). Q. What is the Balanced Portfolio? A. As I noted earlier, the Balanced Portfolio is an SPP strategic initiative to develop a cohesive grouping economic transmission upgrades that benefit the SPP region and allocate the costs those upgrades regionally. Projects in the Balanced Portfolio include transmission upgrades -kv transmission facilities that are intended to reduce congestion on the SPP transmission system, thus resulting in savings in generation production costs. These economic

26 Case No. -00-UT 0 upgrades may provide other benefits to the power grid, such as increasing reliability and lowering required reserve margins, deferring reliability upgrades, and providing environmental benefits due to more efficient operation assets and greater utilization renewable resources. The portfolio projects approved by the SPP Board Directors is designated as the Portfolio E Adjusted. Q. What is a high-priority upgrade? A. High-priority upgrades are network upgrades identified through a high priority study as directed for construction by the SPP Board Directors in accordance with Attachment O the SPP Tariff. Q. What is a Sponsored Upgrade? A. Sponsored Upgrades are network upgrades, requested by a Transmission Customer or other entity, that do not meet the definition any other category Network Upgrades. Any entity may request that a Sponsored Upgrade be built. SPP evaluates the impact any Sponsored Upgrade on transmission system reliability and identifies any necessary mitigation these impacts. The project sponsor must be willing to assume the cost the Sponsored Upgrade, study costs, and any cost associated with necessary mitigation. 0

27 Case No. -00-UT Q. What is an Interregional Project? A. An Interregional Project is defined in FERC Order No. 000 as a project which starts in one region and ends in another region. The ITP has been enhanced to include coordination with neighbors SPP. The enhancements include model development, issues identification, and solution development.. SPP Cost Allocation for New Transmission Infrastructure 0 Q. Is SPS affected by the SPP s method for allocating costs for new transmission infrastructure? A. Yes. In this rate case, SPS s revenue requirement includes SPP costs that have been allocated to SPS under four different allocation methods: () Pre-00; () Original Base Plan Funding; () the Balanced Portfolio; and () the Highway/Byway. A matrix showing the effects these methods during the period July, 0 through June 0, 0 ( Test Year ) is shown in Attachment WAG-. Q. What cost allocation occurred under the Pre-00 method? A. Under this method, transmission owners were allocated all the costs for transmission projects located within their respective service territories. Thus, projects identified prior to 00 had costs allocated in this fashion. It was not

28 Case No. -00-UT 0 until the Original Base Plan Funding method that inter-zonal allocation costs began. Q. Please explain the Original Base Plan Funding for Transmission Upgrades. A. Inter-zonal allocation costs is the method cost allocation for Original Base Plan transmission upgrades. When Network Integration Transmission Service ( NITS ) or Reliability Transmission Upgrades are implemented, those SPP transmission customers benefitting most directly from the upgrade pay / the costs with the remaining SPP transmission customers paying the remaining / the costs. These upgrades were required to maintain reliability the electric transmission grid. This methodology was utilized for projects identified from 00 until June 00. Q. How are the costs the Balanced Portfolio projects allocated to SPP members? A. The allocation costs associated with the Portfolio E Adjusted projects is intended to balance the benefits over the entire SPP region. To achieve balance among the SPP members as the actual construction costs the projects are included in rates, the Balanced Portfolio process contains a reallocation mechanism that reallocates a portion a zone s zonal revenue requirement to the

29 Case No. -00-UT 0 region-wide postage stamp revenue requirement. A benefit-to-cost ( B/C ) analysis was performed to ensure that the benefits were greater than the cost the projects. In the analysis, the benefits were also done on a zone by zone basis to ensure that every zone showed benefits greater than the allocated cost on a load ratio share or that zone would receive transfer payments to bring the deficient zone back to a to B/C ratio. This method balancing reduces costs to deficient zones to ensure that no zone is disadvantaged by paying costs for economic upgrades for which it receives little or no benefit. Q. Have these transfer payments associated with the Balanced Portfolio started? A. Yes. In August 0, SPP filed revisions to its OATT to implement the initial reallocation revenue requirements under Attachment J (FERC Docket No. ER-). The initial reallocation was authorized under the Balanced Portfolio because at least 0% the levelized annual transmission revenue requirements for the approved Balanced Portfolio had been included in rates (i.e., the Trigger Date ). On each anniversary the Trigger Date in the subsequent four years, an additional 0% the Reallocated Revenue Requirement was or See Attachment J the SPP OATT at

30 Case No. -00-UT 0 shall be transferred to the Total Balanced Portfolio Region-wide Annual Transmission Revenue Requirement ( ATRR ). The FERC issued an Order on November 0, 0: () accepting SPP s request to implement the initial reallocation revenue requirements effective October, 0; and () authorizing all subsequent annual reallocations for years two through five to occur on the October st anniversary dates. On October, 0, the SPP then implemented its year-five reallocation revenue requirements for the Balanced Portfolio (Attachments J and O). Q. Turning now to the fourth allocation method you listed, what is the Highway/Byway cost allocation? A. The current Highway/Byway funding methodology was approved by the FERC in 00. This process splits the funding into three different categories: () projects less than 00 kv; () projects at or above 00 kv but below 00 kv; and () projects 00 kv and higher. This methodology replaced the prior methods cost allocation. Under Highway/Byway funding, projects below 00 kv are 00 percent funded by the zone in which they are built, projects between 00 kv and 00 kv are funded / regionally and / by the zone in which they are built, and

31 Case No. -00-UT 0 projects over 00 kv are 00 percent regionally funded on a load ratio share basis. Q. How does the SPP administer these cost allocations and collect the revenue for the regional transmission funding? A. SPP administers the process through the methodologies contained in Attachment J the SPP OATT and recovers the revenue through the resulting Schedule charges under the SPP OATT. SPP collects both the zonal and any regionally allocated costs under Schedule. SPP then distributes this revenue to the Transmission Owners in accordance with their respective Attachment J the SPP OATT.. SPP Directives to Construct Facilities Q. For purposes the Test Year and beyond, how are entities selected to construct transmission facilities? A. As part FERC Order No. 000, all public utility transmission providers (including RTOs) were required to remove from their FERC-jurisdictional tariffs and agreements any provisions that granted a federal right first refusal to a current ( incumbent ) public utility transmission provider to construct regional transmission facilities if the costs such facilities are allocated to customers

32 Case No. -00-UT 0 outside the incumbent utility s retail distribution service territory or footprint. The removal the federal right first refusal potentially allows non-incumbent transmission developers to compete for the right to construct certain transmission lines on essentially the same basis as incumbents. Q. Please describe how the right to construct certain transmission facilities will be subject to competition. A. As a part SPP compliance filings in FERC Docket Nos. ER--000 and ER--000, FERC approved a TO Selection Process to competitively solicit proposals for the construction Competitive Upgrades approved by the SPP Board Directors beginning on January, 0 and for which no right first refusal existed. For Competitive Upgrades, SPP will solicit proposals using the TO Selection Process. A request for proposals will be published by SPP for each Competitive Upgrade project which is approved for construction or endorsed by the SPP Board Directors after January, 0. Any qualified participant may submit a response within 0 days the publication the request for proposals. The Sw. Power Pool, Inc., FERC,0 (0). The most recent order issued by the FERC accepting SPP Order No. 000 compliance filings is dated August, 0, when the FERC accepted the fourth compliance filing from SPP. See Sw. Power Pool, Inc., FERC,0 (0).

33 Case No. -00-UT 0 response time may, however, be reduced to no less than 0 days based on the need date or scope the project. All response submissions will be reviewed and evaluated by an Industry Expert Panel. After completing the evaluation all submitted responses, the Industry Expert Panel will recommend a proposal for each Competitive Upgrade to the SPP Board Directors. Q. What occurs after the Industry Expert Panel provides its recommended proposal for each Competitive Upgrade to the SPP Board Directors? A. The SPP Board Directors will select the winning bid. The developer who submitted the winning bid will become the Designated Transmission Owner ( DTO ), and SPP will issue a Notification to Construct ( NTC ) to the DTO for the transmission project. The selected developer may assign the NTC to an affiliate. Q. What occurs if the transmission project identified by SPP does not meet the definition a Competitive Upgrade and, thus, is not eligible for competitive bidding? A. In that case, the NTC will be issued to the TO in whose service territory the project is to be located. After projects have been identified and approved, SPP will issue an NTC within business days for each Network Upgrade for which a financial commitment is needed within the next four years. The NTC includes the

34 Case No. -00-UT 0 specifications the project required by SPP and a reasonable project schedule, including a project completion date. This is specified under section 00 the SPP OATT Business Practices. Q. What are the responsibilities the DTO when an NTC is received for non- Competitive Upgrade transmission projects? A. To maintain its right to construct, the DTO is required to respond within ninety days after the receipt the NTC. The DTO can respond with a commitment to construct as specified or submit a response with a different project schedule or alternative specifications. If an amended proposal is provided by the DTO, then SPP responds within ten days the receipt the amended proposal. If the amended changes are rejected by SPP, the TO can still accept the proposal if it is within the ninety-day window. Q. What happens if the DTO does not accept the NTC for a non-competitive Upgrade transmission project within ninety days? A. In that event, SPP solicits bids and evaluates proposals from other entities to construct the project. SPP will then select a qualified entity based on, among

35 Case No. -00-UT 0 other things, certain specific legal, regulatory, technical, financial, and managerial qualifications. Upon selection, the replacement designated provider becomes the DTO. Q. What happens if SPP is unable to find another qualified entity to construct a project? A. The originally identified DTO will continue to have the obligation to construct the project under Section VI. Attachment O and Section.(a) the SPP membership agreement. Q. Can a DTO transfer its legal right to build? A. Yes. Under section 00 the SPP Business Practices, a DTO can assign or transfer its legal right to build. This assignment does not relieve the original DTO the legal obligation to ensure that the project is built. Q. Could the original DTO ever be released from the obligation to ensure that a project is built? A. Yes. The original DTO can novate its obligation to build to another TO. The SPP Board Directors must approve the novation. Q. How active is SPS in SPP s planning process? A. During the assessment period, SPS personnel are very active in assessing the projects and the alternatives, if any, to the proposed projects. The SPS personnel

36 Case No. -00-UT 0 work with the SPP planning department in developing projects that meet the needs the SPS area. Q. Has SPS identified alternatives to NTCs that saved money for SPS s customers? A. Yes. SPS routinely reviews NTCs and, when prudent, requests SPP either re-evaluate or confirm the need for identified projects. One example is for an NTC related to a 0-kV transmission line proposed from Seminole County to Hobbs County. The NTC for this project was issued to serve expected load in the area. SPS s projection load differed from what SPP had used in developing the NTC. Thus, SPS requested SPP to re-evaluate and confirm the expected load for the project. Upon reconsideration, SPP agreed with SPS s load projection and the NTC was cancelled. The cancellation avoided approximately $ million total capital expenditures and approximately $ million annual Schedule charges for SPS. Another example is an NTC for a new Frio Draw -kv substation near Portales, New Mexico, and a new -kv transmission line from Frio Draw to Potter County, Texas. Based upon SPS s review, it determined that future generation was not fully considered by SPP in developing the NTC. SPS 0

37 Case No. -00-UT 0 requested SPP to re-evaluate the extent the construction included in the NTC in light the expected generation. SPP agreed with SPS that the NTC could be withdrawn, which avoided approximately $. million total capital expenditures and approximately $ million annual Schedule charges for SPS. In addition, SPS requested the withdrawal an NTC for a -kv line from Crosby to Floyd. During internal evaluation, it appeared that another, already-issued NTC would address a similar need and, thus, the Crosby to Floyd line was not needed. The withdrawal this NTC avoided approximately $ million total capital expenditures and approximately $. million annual Schedule charges for SPS. Q. How does the SPP s transmission planning function affect SPS? A. As discussed previously, the Schedule charges assessed according to the SPP Tariff are based on a number factors to loads in SPP. SPS is located in Zone. As such, the retail customers SPS are assessed Schedule charges for their share regional transmission projects and their share transmission

38 Case No. -00-UT 0 system projects in Zone. Mr. Freitas discusses specific Schedule charges assessed by SPP to SPS that are reflected in the Test Year. Q. What trend in the assessment Schedule charges does SPS expect in the near future? A. SPS expects the assessment Schedule charges to increase over the next several years. However, while Schedule charges are expected to increase, I also expect the amount revenues received by SPS under Schedule to increase, as well. The expected increase in revenues is due to the completion by SPS regional transmission projects in Zone whose costs will be regionally allocated. Q. Despite the expected increase in Schedule charges SPS estimates over the next few years, will SPS continue to receive net benefits from the SPP Transmission Expansion Plan? A. Yes. In January 0, the SPP s MOPC, RSC, and Board Directors endorsed a report that recommended transmission benefits be evaluated by the Economic Schedule charges are one type wheeling charge. Examples other types wheeling charges are SPP Schedule charges (firm point-to-point transmission service), SPP Schedule charges (non-firm point-to-point transmission service), SPP Schedule charges (Network Integration Transmission Service), charges under the Xcel Energy Open Access Transmission Tariff, and charges for purchasing transmission service from a transmission provider outside the SPP. In addition, to wheeling charges, there are charges for services and operations such SPP Schedules, -A,, and.

39 Case No. -00-UT 0 Studies Working Group ( ESWG ) for the purpose the regional cost allocation review ( RCAR ). In February 0, the ESWG initiated a Metrics Task Force ( MTF ) with the purpose developing tangible, monetized transmission benefit metrics for economic evaluations. In September 0, the MTF completed its report, which contained a list recommended transmission benefit metrics. These metrics were approved by the MOPC, RSC, and the SPP Board Directors in October 0. The Brattle Group was selected to perform the RCAR, using the metrics established by the MTF, as well as SPP ITP metrics. The RCAR results were released on July, 0. A final report was released on October, 0 (referred to below as the original RCAR report) and was approved by the SPP Board Directors at its October 0 meeting. Q. Please describe the methodology used in the RCAR. A. Two studies were undertaken as a part the RCAR to show the benefits and costs by each pricing zone within SPP : () transmission projects that have received NTCs since June 00; and () projects that have received an NTC since June 00, plus the SPP Board Directors-approved transmission projects that have received an Authorization to Plan ( ATP ) with in-service dates ten years or less. The studies use a 0-year assessment to evaluate transmission project

40 Case No. -00-UT 0 costs and benefits. The RCAR treated projects with NTCs with greater weight than those with ATPs. The benefits the projects considered under the RCAR consist :. Adjusted Production Cost ( APC ) i. Emission Rates and Values ii. Ancillary Service Needs and Production Costs;. Avoided or Delayed Reliability Projects;. Capacity Cost Savings due to Reduced On-Peak Transmission Losses;. Mitigation Transmission Outage Costs; and. Benefits Public Policy Goals. The most up to date ATRR for each zone was used to calculate the costs transmission projects. The RCAR then developed B/C ratios for each SPP pricing zone based upon the transmission project costs and benefits. Q. What APC savings did the original RCAR report show on an SPP-wide basis and for SPS? A. On an SPP-wide basis, the original RCAR report showed a 0-year NPV APC savings $. billion for NTCs, $ million for suspended NTCs, and $ million for ATPs. For the SPS pricing zone, the estimated 0-year present value

41 Case No. -00-UT 0 0 APC savings was $. billion for NTC projects, $0 million for suspended NTCs, and $ million for ATP projects. Q. What was the B/C ratio for the SPS pricing zone under the original RCAR report? A. The estimated B/C ratio for the SPS pricing zone had a range. to. under various sensitivities, meaning that at a minimum for every dollar spent on projects, the RCAR estimates that SPS is receiving $. (at the lower the range) benefits. Q. Has there been a more recent RCAR report? A. Yes. The RCAR is a process that occurs at least every three years. However, as a part the 0 ITP 0 Year assessment, an update to the RCAR was provided in July 0. Q. What are the results the metrics for the July 0 RCAR report? A. Overall, the July 0 RCAR report showed increased benefits versus what was presented in the original RCAR report. Below is a summary several metrics from the July 0 RCAR report:. On an SPP-wide basis, the 0-year NPV APC savings is $. billion for NTCs. a. For the SPS pricing zone, the 0-year present value the ATRRs is a little under $. billion.

42 Case No. -00-UT 0 0. On an SPP-wide basis, the benefits avoided or delayed reliability projects for NTC projects are $ million in 0 dollars. a. For the SPS pricing zone, the estimated benefits relating to the NTC projects is $ million.. On an SPP-wide basis, the 0-year NPV Capacity savings due to Reduced On-Peak Transmission Losses is $ million. a. For the SPS pricing zone, the 0-year estimated benefits are $ million.. On an SPP-wide basis, the 0-year NPV benefits related to mitigation transmission outage costs is $.0 billion. a. Each SPP pricing zone receives these benefits based on its load ratio share.. On an SPP-wide basis, the benefits is $. billion in 0 dollars related to mandated reliability projects. a. For the SPS pricing zone, $.0 billion in 0 dollars is estimated to result from NTC, suspended NTC, and ATP projects.. On an SPP-wide basis, an increase wheeling through and out revenues $ million is estimated. a. For the SPS pricing zone, an increase wheeling through and out revenues $0 million is estimated. Q. What is the B/C ratio for the SPS pricing zone under the July 0 RCAR? A. The estimated B/C ratio for the SPS pricing zone is. versus a B/C ratio. in the original RCAR. A web link to the July 0 RCAR report is:

43 . SPP Expansion Case No. -00-UT 0 Q. In addition to the FERC Order No. 000 developments you discussed, have other transmission planning activities occurred? A. Yes. On October, 0, Western Area Power Administration ( WAPA ) - Upper Great Plains Region, Basin Electric Power Cooperative ( Basin Electric ), and Heartland Consumers Power District ( Heartland ) (collectively referred to as the Integrated System ) joined SPP as Transmission Owning Members. In particular, on October, 0, these three entities successfully transferred functional control the integrated transmission system to SPP and began operating in the SPP RTO. Q. Further describe WAPA, Basin Electric, and Heartland. A. WAPA is a federal power marketing agency that markets federal power and owns and operates transmission facilities throughout western and central states, encompassing a geographic area. million square miles. Basin Electric is one the largest generation and transmission cooperatives in the United States. Basin Electric membership serves. million customers in territories covering approximately 0,000 square miles throughout states. Heartland is a public corporation and political subdivision the State South Dakota. Heartland

44 Case No. -00-UT provides reliable, low-cost, wholesale power to municipalities in eastern South Dakota, southwest Minnesota, and northwest Iowa, to six South Dakota state agencies, and to one electric cooperative in South Dakota. These three entities collectively own and operate the bulk electric transmission system in the Upper Great Plains region the United States, including approximately,00 miles transmission lines rated -kv through -kv stretching across a seven-state region.. Attachment Z 0 Q. Is your discussion Attachment Z related to any other SPS proceeding pending before the Commission? A. Yes. On October, 0, SPS filed an application asking the Commission for permission to record in a deferred account and to pass through to New Mexico retail customers certain back-billed charges assessed under Attachment Z the SPP OATT ($. million, total company). In that application, SPS explained that it would seek to recover the New Mexico retail portion the back-billed expense in a future rate proceeding. In this rate case, SPS is seeking to recover that expense. Mr. Freitas explains that SPS has amortized the back- Application Southwestern Public Service Company for an Accounting Order Related to Backbilled Charges by the Southwest Power Pool, Inc., Case No. -00-UT (pending).

45 Case No. -00-UT 0 billed expense over a five-year period and has included an annual amortization expense in the Test Year cost service. Mr. Freitas will address how the expense is treated for ratemaking purposes. In my testimony, I will explain Attachment Z and the history leading to the backbill from the SPP to SPS. Q. What is Attachment Z? A. To understand what is now Attachment Z, it is necessary to appreciate the context in which its forerunner, Attachment Z, was proposed and approved. Before 00, SPP evaluated each long-term transmission service request on a sequential basis, without considering whether any lower-queue requests might have comparable system impacts. In addition, the cost each transmission upgrade was charged to the utility that constructed the upgrade. Although that approach worked reasonably well when the entity planning and constructing the upgrades was a single utility, it proved to be inefficient and ultimately unworkable on a region-wide basis. Thus, on October, 00, SPP asked FERC to approve Attachment Z, which prescribed an aggregate transmission service study process by which SPP would combine all long-term point-to-point and long-term designated network resource requests received during a specified time period into a single aggregate

46 Case No. -00-UT transmission service study. According to SPP, the aggregation transmission service requests would result in an optimal expansion [SPP s] transmission system... at the minimum total cost. 0 In addition, the proposed Attachment Z would assign cost responsibility for upgrades to those customers who would benefit from the upgrade. Finally, the proposed Attachment Z provided that, if a 0 particular customer or group customers funded a particular upgrade, the customer or customers would be entitled to revenue credits if the upgrade allowed SPP to provide new transmission service that would not have been possible in the absence the upgrade. Q. Did FERC approve the proposed Attachment Z? A. Eventually, yes. FERC initially expressed concerns about the interrelationship between Attachment Z and other cost allocation provisions that had been Southwest Power Pool, Inc., Docket No. ER0-0, Submission Proposed Tariff Revision Aggregate Transmission Service Study Procedures (Oct., 00). 0 Id. at. Id. ( The cost each transmission upgrade component will be allocated to each customer in the aggregation group on a pro-rata impact basis for the positive incremental power flow impacts the requested service on such upgraded facility in proportion to the total all incremental impacts on such upgraded facility. ). Id. at ( Any charges paid by a customer in excess the transmission service base rate shall be credited back to the customer from future transmission service revenues until the customer has been fully compensated. ). 0

47 Case No. -00-UT proposed for the SPP OATT. In response, SPP submitted a new filing clarifying 0 some the cost allocation and recovery provisions in the OATT. Those additional filings satisfied FERC, which issued an order approving Attachment Z and several other parts the SPP OATT on April, 00. Q. Did SPP then begin implementing Attachment Z? A. SPP began implementing Attachment Z in part. It began conducting aggregate transmission service studies, and it allocated the costs network upgrades in accordance with the methodology outlined in Attachment Z. However, SPP and its stakeholders concluded that the process set forth in Attachment Z lacked the specificity necessary to calculate revenue credits. Therefore, in 00 SPP filed revisions to the SPP OATT separating Attachment Z into two attachments: () Attachment Z, which prescribed the methodology for performing aggregate transmission studies and for allocating costs network upgrades; and () Attachment Z, which prescribed the methodology for calculating revenue credits owed to customers who had funded projects. Southwest Power Pool, Inc., Order Accepting and Suspending Tariff Filing, 0 FERC,0 (00). Southwest Power Pool, Inc., Order on Proposed Tariff Revisions, FERC, (00).

48 Case No. -00-UT 0 Q. Did FERC approve Attachment Z? A. Yes. On May, 00, FERC accepted the proposed revisions to Attachment Z. Q. Did the 00 revision broaden the revenue crediting process in any way? A. Yes. The original Attachment Z provided revenue credits only as a result the aggregate study process. As part the 00 revisions, customers who had paid for generation interconnection requests outside the aggregate study process also became eligible for revenue credits. In addition, the language was clarified to state that any Project Sponsor would be eligible for revenue credits. Finally, the revisions provided that revenue credits would be based on transmission service that could not have been provided but for the existence the Creditable Upgrade. Q. Did the 00 adoption Attachment Z provide SPP with the clarity it needed to begin collecting and distributing revenue credits? A. No. Despite FERC s approval Attachment Z in 00, SPP did not begin providing revenue credits to Project Sponsors at that time. According to SPP, the Southwest Power Pool, Inc., Order Accepting in Part and Rejecting in Part Tariff Changes, and Directing Compliance Filing, FERC,0 (00).

49 Case No. -00-UT process calculating revenue credits under Attachment Z involved substantial complexity resulting from numerous elements. Q. How did SPP and its stakeholders address that complexity? A. SPP and its stakeholders concluded that a more detailed process and a calculation methodology needed to be developed before SPP could effectively implement the revenue crediting process. In 00, SPP s RTWG formed the Crediting Process Task Force to work with SPP and its stakeholders to develop processes and mechanisms to implement the revenue credits. According to SPP, the Crediting Process Task Force worked from April 00 through June 0 to create a white 0 paper on certain aspects the crediting process. In July 0, the SPP MOPC voted to implement the revenue crediting process as provided in the white paper, and in January 0 the MOPC decided to move forward with development stware designed to calculate the revenue credits. In October 0, SPP engaged a vendor to develop the stware necessary to implement the revenue crediting process. Southwest Power Pool, Inc., Docket No. ER-, Petition Southwest Power Pool for Tariff Waiver at (Apr., 0). Id.

50 Case No. -00-UT 0 Q. Did the stware vendor provide a product that SPP could use to calculate revenue credits? A. No. The target date for the vendor to provide SPP with the finished stware was October 0, and SPP planned to implement the revenue crediting process by May 0. But after numerous delays, SPP determined that the vendor could not deliver functional stware, so SPP engaged a new vendor in early 0 with a goal full implementation in 0. Q. Was the new vendor ultimately able to provide stware that allowed SPP to calculate revenue credits? A. Yes. The replacement vendor delivered operational stware to SPP in early 0, and SPP used that stware to calculate not only the revenue credits payable to the project sponsors, but also the amounts owed by transmission customers and transmission owners that had made use the Creditable Upgrades. SPP quantified the amount owed by each transmission customer or transmission owner in September 0, and SPP has indicated that it intends to begin invoicing transmission customers for the back-billed amounts in November 0.

51 Case No. -00-UT 0 Q. Did SPP seek FERC approval to bill transmission customers for the revenue credits it plans to distribute to Project Sponsors? A. Yes. On April, 0, SPP filed a petition at FERC seeking waiver to implement the revenue crediting process as it has been clarified since being added to the [SPP OATT] in 00 and 0, to permit [SPP] to calculate, collect and pay revenue credits in accordance with Attachment Z. Q. What types waivers did SPP seek from FERC? A. SPP sought three specific waivers. First, SPP asked FERC for a waiver Section. the SPP OATT, which provides that, with limited exceptions, billing adjustments shall be limited to those corrections and adjustments found to be appropriate for such service within one year after rendition the bill reflecting the actual data for such service. That is, Section. generally prevents SPP from engaging in back-billing for events that happened more than a year before the issuance a bill. In its petition, SPP noted that the settlement the credit amounts could reasonably be viewed as an initial settlement and, therefore, did not constitute back-billing at all because [SPP] has not yet attempted to collect Southwest Power Pool, Inc., Docket No. ER--000, Petition Southwest Power Pool, Inc. for Tariff Waiver (April, 0).

52 Case No. -00-UT these amounts from transmission customers. SPP nevertheless requested a waiver the one-year back-billing limitation out an abundance caution. Second, SPP sought a waiver the requirement that it reallocate Balanced Portfolio transfer amounts affected by the revenue credit calculations. SPP asserted that the reallocations Balanced Portfolio transfer amounts would be minimal, and, therefore, the recalculations necessary to quantify the amounts would create an undue burden with little benefit. Third, SPP asked FERC for a waiver the OATT section that requires transmission customers to request a waiver the Safe Harbor Cost Limit for 0 network upgrades within a certain time. According to SPP, the delay in implementing Attachment Z had deprived transmission customers the opportunity to request a waiver costs in excess the Safe Harbor Cost Limit that would otherwise be available to them. SPP further noted that a waiver would allow the posting the excess costs, after which transmission customers would have an opportunity to review the costs and request a waiver the excess costs. The Safe Harbor Cost Limit provides that, if the cost network upgrades required to grant a transmission customer s request for transmission service exceeds $0,000 per megawatt, the excess costs will be directly assigned to the transmission customer unless the customer is granted a waiver these costs by the SPP Board Directors. All eligible network upgrade costs below the Safe Harbor Cost Limit are Base Plan funded. Southwest Power Pool, Inc., FERC,00 at P n..

53 Case No. -00-UT 0 Q. Did any parties protest SPP s request for waivers? A. Yes. SPS and several other SPP stakeholders objected to SPP s request on numerous grounds, including the financial hardship that results from billing for events that extend back to 00. Through its affiliate XES, SPS argued that any revenue credits collected by SPP should be prospective only and that SPP should be required to describe and justify its recovery methodology before implementing it. Along with several other parties, SPS also argued that SPP had not satisfied the criteria for a waiver under FERC s standards for evaluating waiver requests. Q. How did FERC rule on the request for waivers? A. FERC granted SPP s request for waivers. FERC acknowledged that the resettlement is expected to involve a significant sum money and spans eight years, but FERC concluded the resettlement is a necessary, one-time waiver three discrete Tariff provisions that will allow [SPP] to implement the revenue crediting mechanism under the SPP OATT. 0 The overriding consideration, from FERC s perspective, was that the waiver would allow project sponsors to be properly compensated in accordance with Attachment Z. 0 FERC,00 at P. Id. at P.

54 Case No. -00-UT Q. Did any parties move for rehearing FERC s decision to grant SPP s request for a waiver? A. Yes. XES and several other parties filed motions for rehearing, which remain pending before FERC. FERC has granted rehearing for the limited purpose giving itself more time to consider the motions for rehearing. Q. Have there been any other FERC proceedings related to the back-billing? A. Yes. In response to concerns expressed by stakeholders about the burdens caused by the back-billing, SPP petitioned FERC on July, 0 for approval a plan to allow affected parties the option paying all back-billed amounts in one lump 0 sum or paying the back-billed amounts over a five-year period. FERC granted SPP s waiver request on September 0, 0. The payment plan approved under that waiver provides the following: If the five-year payment plan is selected, the transmission owner or transmission customer (which is referred to in the Z Payment Plan Election Acknowledgement as a Z Impacted Entity ) agrees to pay its net payable balance for the March 00-August 0 period in twenty equal installments every three months during a five-year term. E.g., Southwest Power Pool, Inc., Docket No. ER--00, Request for Rehearing American Electric Power Service Corporation and Xcel Energy Services Inc. (Aug., 0). Southwest Power Pool, Inc. Docket No. ER--00, Order Granting Rehearings for Further Consideration at (Sept., 0).

55 Case No. -00-UT The length the Attachment Z payment plan may not be modified (i.e., reduced or expanded). SPP will apply interest at the rate established under CFR.a(a)() to the outstanding net payable balance. 0 Q. Earlier you stated that SPP has indicated that it intends to begin invoicing transmission customers for the back-billed amounts in November 0. Has SPP quantified the amount revenue credits that it intends to collect from the Z Impacted Entities? A. Yes. In September 0, the SPP Staff quantified the amount payable to or from each Z Impacted Entity. According to SPP, SPS owes $,,. That amount represents the net the Attachment Z amount owed to SPS, which is $,0, (total company), and the Attachment Z amount owed by SPS, which is $,, (total company). Table WAG- separates the total amount into its component parts: Southwest Power Pool, Inc., FERC, at P (stating that SPP must calculate the amounts owed under the Payment Plan based on the current interest rate for each quarter, as well as ensure that interest be calculated at each quarter on the initial principal amount owed, and also on the accumulated interest the previous periods ).

56 Case No. -00-UT 0 Type Charge Table WAG- Amount Expected to be Billed by SPP Schedule Base Plan Charges $,, Direct Assigned Upgrade Costs $,0 Credit Distributions SPS Funded Upgrades $(,0,) PTP Revenue Clawback $,, Total $,, Q. According to Table WAG-, most the charges are labeled as Schedule Base Plan Charges and PTP Revenue Clawback, with only a small fraction the total amount characterized as Direct Assigned Upgrade Costs. Why is that? A. Under the SPP OATT, costs that began as Direct Assigned Upgrade Costs are recategorized as Schedule costs if: () they allow SPP to fer transmission service that it would not have been able to provide in the absence the upgrade; () the network upgrade qualifies as a Base Plan Upgrade eligible for Schedule cost recovery; and () the costs are below the Safe Harbor Cost Limit set forth in the OATT. All the original Directly Assigned Upgrade Costs that satisfied those criteria are categorized by SPP as Schedule Base Plan Charges. Costs above the Safe Harbor Cost Limit are not eligible for Base Plan funding and, therefore, remain categorized as Directly Assigned Upgrade Costs. 0

57 Case No. -00-UT 0 The PTP Revenue Clawback amounts represent revenues that SPS received for point-to-point transmission service that was made possible, in whole or in part, by the Creditable Upgrade facilities. Under Attachment Z, those revenues are clawed back and paid to the sponsors the Creditable Upgrades. Q. Over what period will SPS pay the $. million to SPP? A. In its capacities as both a transmission customer and a transmission owner, SPS elected the five-year payment plan. Accordingly, SPS must pay the total net amount owed in 0 installments over a five-year term beginning in November 0, and SPS will continue to pay the back-billed amounts until the last quarter 0. SPS must also pay interest on the unpaid balance at the rate set forth in CFR.a(a)(). Q. Why did SPS elect to pay the Attachment Z amounts over a five-year period rather than paying them in one lump sum? A. The five-year period approximates the time period over which SPS expects the costs to be recovered from customers. The interest rate prescribed by CFR.a(a)() is the average prime rate for each calendar quarter, which is defined as the arithmetic mean, to the nearest one-hundredth one percent, the prime rate values published in the Federal Reserve Bulletin, or in the Federal Reserve s Selected Interest Rates... for the fourth, third, and second months preceding the first month the calendar quarter.

58 Case No. -00-UT 0 Q. Is it reasonable to ask SPS s New Mexico retail customers to pay the backbilled amounts charged by SPP? A. Yes. It is reasonable and equitable for New Mexico retail customers to pay the back-billed Attachment Z charges because those customers have benefited from the Creditable Upgrades that give rise to the Attachment Z charges and from the prior point-to-point revenues. Q. Why do you state that New Mexico retail customers have benefited from the Creditable Upgrades for which they will receive Attachment Z charges and from the prior point-to-point revenues? A. As I explained earlier, the bulk the amounts are attributable to Schedule Base Plan Upgrades. SPS s New Mexico retail customers benefit from Schedule Base Plan Upgrades, including the Creditable Upgrades, because, among other things, those upgrades enhance the reliability the bulk transmission system and provide access to lower-cost power outside the SPS service area. For example, the Oklahoma Gas and Electric -kv Wind Speed line from Woodward, Oklahoma to the Oklahoma City area provides another strong -kv source to the Woodward area that connects the Woodward to Hitchland -kv tie line to

59 Case No. -00-UT 0 the SPS area. This line helps strengthen the connection the SPS transmission grid to the rest the Eastern Interconnection. Finally, in the four base rate cases SPS has filed since 00, point-to-point revenues have been included in the requested cost service as a revenue credit, which reduced the revenue deficiency in the proposed cost service in all those cases. Three those four rate cases were resolved through settled revenue requirements, but the starting dollar amount SPS presented leading into the settlement discussion reflected the revenue credit. For the one litigated base rate case during this period, Case No UT, the revenue credits were reflected in the approved revenue requirement and, thus, SPS customers received the benefit the point-to-point revenues that are being clawed back by SPP. Q. Are the back-billed charges associated with Attachment Z the only Z charges SPS is requesting in its Test Year revenue requirement? A. No. The Attachment Z charges that are attributable to the period after September, 0 are standard SPP charges and are included as routine operation and maintenance expenses in this case. Mr. Freitas addresses the ratemaking treatment these routine Z charges.

60 Case No. -00-UT D. Market Operations 0 Q. Earlier you stated that SPP replaced the EIS Market with the Integrated Marketplace on March, 0. Please discuss SPP s Market Operations function before March, 0. A. In 00, SPP implemented the EIS Market, which was a wholesale market that operated under a tariff approved by the FERC. The EIS was intended to: () reduce the overall production costs serving load by optimizing the dispatch generation across the SPP footprint; and () improve reliability through more precise control power flows on the transmission system. SPP administered the EIS, oversaw market activities, ensured reliability, forecasted supply requirements, and provided market monitoring oversight. In the EIS, a market participant settled with SPP for imbalance service when a difference occurred between a generator s scheduled output or a load s scheduled withdrawal and the actual metered generator output or load withdrawal volumes in an hour. The EIS utilized Locational Imbalance Prices ( LIP ), which were calculated every five minutes, but averaged over the hour to create hourly settlement prices. The LIP reflected the incremental cost delivering energy to specific locations on the transmission grid. The EIS was an optimal dispatch

61 Case No. -00-UT 0 solution for units that the market participants had committed to meet their load and reserve obligation. In the EIS, SPP was not the responsible party for committing units. Q. Please discuss SPP s Market Operations function beginning March, 0. A. On March, 0, SPP commenced the new Integrated Marketplace for the region, which moved SPP to a two-settlement, locational marginal price ( LMP ) energy market model, like the MISO, the Pennsylvania, Jersey, Maryland Power Plant independent system operator, and other established RTOadministered markets. Q. Please describe how the SPP Integrated Marketplace operates. A. The SPP Integrated Marketplace includes day-ahead and real-time energy and operating reserve markets and transmission congestion rights markets. The Integrated Marketplace uses a two-settlement system where participants make binding day-ahead financial commitments and then settle any deviations from their day-ahead commitments or load forecast in a real-time balancing market. In this way, SPP determines the most cost-effective generating units to commit and dispatch the following day, determines the required reserves, increases the

62 Case No. -00-UT 0 balancing regional supply and demand, and aids in the integration renewable resources. Furthermore, the then existing sixteen Balancing Authorities in the SPP market footprint were consolidated into a single Balancing Authority to effectuate the SPP Integrated Marketplace. Thus, SPP now serves as the reliability coordinator, balancing authority, transmission service provider, planning coordinator, reserve sharing group administrator, interchange authority, and market operator. Q. Please describe the day-ahead market component the SPP Integrated Marketplace. A. The SPP s day-ahead market determines the least-cost solution to meet the market s energy needs and reserve requirements. To accomplish this objective, market participants submit fers to sell services provided by generation including energy, reserves, and other ancillary services. Market participants serving load bid in their forecasted load to be cleared in the market. SPP then performs a security constrained economic dispatch, which is a co-optimization algorithm to clear, dispatch, and price energy and operating

63 Case No. -00-UT 0 reserves to minimize overall costs. The process results in the most cost-effective mix resources to meet the load forecast for the operating day. The day-ahead market also includes a must fer requirement equal to the amount submitted load in the day-ahead settlement to ensure enough physical resource capacity to satisfy the need the market. The must fer requirement is required all generation for the reliability unit commitment ( RUC ) performed in the real-time market. Q. Please describe the day-ahead RUC process, transmission congestion rights markets, and the multi-day reliability assessment associated with the SPP Integrated Marketplace. A. The day-ahead RUC is a co-optimization algorithm for committing resources to supply energy and/or operating reserves to minimize capacity costs. After the day-ahead market has cleared, SPP will begin the day-ahead RUC process. This process is designed to ensure there are adequate physical resources to meet the SPP s load forecast and operating reserve requirements. SPP starts this process one hour after posting the day-ahead market results to determine whether there is adequate capacity for the following operating day. SPP then updates the operating plan and issues start-up and shut-down orders as needed.

64 Case No. -00-UT 0 In regards to transmission, SPP implements auction revenue rights ( ARR ) and transmission congestion rights ( TCR ) to assist in managing the cost congestion. These rights will not manage congestion costs by scheduling based on physical rights, but instead provide participants with financial tools to protect themselves from congestion costs. Lastly, the SPP s Integrated Marketplace includes a multi-day reliability assessment. This is performed in advance the day-ahead market to identify resources that must be given commitment instructions in advance the day-ahead market RUC process, due to the long lead times. The multi-day assessment is completed three days before the applicable operating day. Q. Please describe the operating reserve market component the SPP Integrated Marketplace. A. The operating reserve market design calls for market procurement and dispatch Regulation Reserve, Spinning Reserve, and Supplemental Reserves. As with the energy market, the operating reserve market is also a multi-settlement market clearing in the day-ahead with deviations being settled in real-time. Offers submitted for any or all services are cleared in priority with a co-optimized algorithm to achieve the least-cost overall solution for energy and reserve products.

65 Case No. -00-UT IV. SPP ADMINISTRATIVE FEE 0 Q. What is the SPP administrative fee? A. The SPP applies the administrative fee to all transmission service customers to cover its expenses for several the services it provides under its OATT, such as reliability coordination, tariff administration, and seams agreements. The fee is annually set by the SPP Board Directors based on the next year s expected budget, including reconciliation from the previous year s over-or-undercollection. The fee is assessed based upon transmission services purchased or provided pursuant to the SPP Tariff. The SPP administrative fee is recorded in FERC Accounts.,., and.. Q. How does the SPP collect these administrative fees? A. The SPP collects these fees through Schedule -A its OATT. Q. What administrative fee is SPS using in its Test Year? A. The Test Year includes the anticipated 0 administrative fee $0. per MWh. SPS witness Arthur P. Freitas addresses this further in his direct testimony.

66 Case No. -00-UT Q. When will the 0 administrative fee be determined? A. The administrative fee for 0 will likely be approved by the SPP Board in December 0. The SPP publication supporting the anticipated 0 administrative fee can be viewed at: Q. Does this conclude your pre-filed direct testimony? A. Yes. 0

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68 Membership Chair - Jim Eckelberger Vice Chair - Harry Skilton Secty Paul Suskie SPP Board Directors/ Members Committee Chair - Jim Eckelberger Vice Chair - Harry Skilton Secty Paul Suskie Regional Entity Trustees Chair Dave Christiano Secty Emily Pennel Regional State Committee President Patrick Lyons Secty Paul Suskie SPP Staff Gen. Manager Ron Ciesiel Cost Allocation Working Group Chair Dallas Rippy Secty Tamika Barker Market and Operations Policy Committee Chair - Noman Williams Vice Chair - Paul Malone Secty - Carl Monroe System Protection & Control WG Chair Louis Guidry Vice Chair Stephen Wadas Secty Doug Bowman Operating Reliability WG Chair Allen Klassen Vice Chair Ron Gunderson Secty Casey Cathey Balancing Authority Operating Committee Chair - Paul Johnson Vice Chair Greg McAuley Secty Kim Gorter SPP Staff President - Nick Brown Executive VP - Carl Monroe Executive VP - Paul Suskie Senior VP - Tom Dunn Senior VP - Mike Ross VP - Michael Desselle, Lanny Nickell, Bruce Rew, Malinda See, Barbara Sugg Transmission WG Chair Travis Hyde Vice Chair Nathan McNeil Secty Kirk Hall Operations Training WG Chair Denney Fales Vice Chair Robert Hirchak Secty Michael Daly Business Practices WG Chair - Grant Wilkerson Vice Chair Secty Ken Quimby Model Development WG Chair Nate Morris Vice Chair Derek Brown Secty - Anthony Cook Project Cost WG Chair Tom Hestermann Vice Chair Brian Studenka Secty Bryce Bowie Change WG Chair Jim Jacoby Vice Chair Michelle Trenary Secty Annette Holbert Oversight Committee Chair - Joshua Martin Secty Michael Desselle Reliability Compliance WG Chair Jennifer Flandermeyer Vice Chair John Allen Secty Kim VanBrimer Corporate Governance Committee Chair - Nick Brown Secty Paul Suskie Critical Infrastructure Protection WG Chair Eric Ervin Vice Chair Mike Lotz Secty Lesley Bingham Finance Committee Chair - Harry Skilton Secty - Tom Dunn Regional Tariff WG Chair David Kays Vice Chair Robert Pick Secty Brenda Fricano Attachment WAG- Page Case No. -00-UT Economic Studies WG Chair - Alan Myers Vice Chair Secty Kelsey Allen Credit Practices WG Chair - Mark Holler Vice Chair - Terri Wendlandt Secty - Phil McCraw Seams Steering Committee Chair - Paul Malone Vice Chair - Bary Warren Secty Clint Savoy Event Analysis WG Chair Jennifer Flandermeyer Secty Ron Losh Human Resources Committee Chair Julian Brix Secty Malinda See Supply Adequacy WG Chair Bradley Hans Vice Chair - Secty - Chris Haley Market WG Chair - Richard Ross Vice Chair Jim Flucke Secty Debbie James Strategic Planning Committee Chair Michael Wise Secty Michael Desselle Updated 0//