UNITED STATES OF AMERICA BEFORE THE FEDERAL ENERGY REGULATORY COMMISSION. Public Service Company of Colorado ) Docket No.

Transcription

1 Page of UNITED STATES OF AMERICA BEFORE THE FEDERAL ENERGY REGULATORY COMMISSION Public Service Company of Colorado ) Docket No. ER PREPARED TESTIMONY OF JOHN WELCH XCEL ENERGY SERVICES INC. ON BEHALF OF PUBLIC SERVICE COMPANY OF COLORADO

2 Page of I. WITNESS IDENTIFICATION AND QUALIFICATIONS Q. PLEASE STATE YOUR NAME AND BUSINESS ADDRESS. A. My name is John T. Welch. My business address is 0 Larimer Street, Denver, Colorado 00. Q. ON WHOSE BEHALF ARE YOU TESTIFYING IN THIS PROCEEDING? A. I am filing testimony on behalf of Public Service Company of Colorado ( PSCo ), a Colorado corporation and electric utility subsidiary of Xcel Energy Inc. ( Xcel Energy ). Xcel Energy is a registered holding company that owns several electric and natural gas utility operating companies. Q. BY WHOM ARE YOU EMPLOYED AND WHAT IS YOUR POSITION? A. I am employed by Xcel Energy Services Inc. ( XES ), the service company subsidiary of Xcel Energy, as Director, Power Operations. Q. PLEASE OUTLINE YOUR RESPONSIBILITIES AS DIRECTOR, POWER OPERATIONS. A. I am responsible for directing the economic dispatch of Xcel Energy s generation and purchase power agreements for the Xcel Energy Operating Companies, including PSCo. Duties in this role include short-term economic resource portfolio optimization, or setting up the system on a next-day basis as well as real-time generation dispatch functions. Additionally, my group engages in 0 economy transactions in real-time, purchasing and selling energy on behalf of PSCo. Xcel Energy is the parent company of the following four wholly owned utility operating companies: Northern States Power Company, a Minnesota corporation; Northern States Power Company, a Wisconsin corporation; PSCo; and Southwestern Public Service Company ( SPS ), a New Mexico corporation (collectively, Operating Companies, or individually, Operating Company ). Xcel Energy s gas pipeline subsidiary is WestGas InterState, Inc.

3 Page of Q. PLEASE DESCRIBE YOUR PROFESSIONAL EXPERIENCE. A. I have fifteen years of experience in system operations at Xcel Energy and its former subsidiary NRG. I have performed various functions within power system operations, including direct control over system dispatch decisions as a North American Electric Reliability Corporation certified system operator. Prior to being promoted to Director, Power Operations in February 00, I was responsible for overseeing the real-time dispatch activities for all four of the Operating Companies for a period of three and a half years as the Manager, Generation Control and Dispatch, and reported to the Director of Power Operations. II. ASSIGNMENT AND SUMMARY OF RECOMMENDATIONS 0 Q. WHAT IS THE PURPOSE FOR YOUR TESTIMONY? A. I will first discuss the reasons for entering into the Joint Dispatch Agreement ( Agreement or JDA ) with Black Hills Colorado Electric Utility Company, LP ( BHCE ) and Platte River Power Authority ( PRPA ) (PSCo, BHCE and PRPA will be referred to jointly as the Parties and individually as a Party ). Where the role of either BHCE or PRPA is referenced with respect to the Agreement, the Party may be indicated as a Participant. I will discuss the public policy reasons for the Agreement and why those public policy reasons support the Federal Energy Regulatory Commission s ( FERC or the Commission ) acceptance of the Agreement. I will discuss both the benefits and costs expected to be produced and incurred under the Agreement. I will then address key components of the Agreement itself to further illustrate how energy sales will occur, as well as

4 how the energy will be priced and delivered. Exhibit PSC- Page of Finally, I will highlight the modifications incorporated into the revised Agreement. Q. PLEASE SUMMARIZE THE CONCLUSIONS AND RECOMMENDATIONS IN YOUR TESTIMONY. A. The Parties have been collaborating to create a joint dispatch arrangement that will realize energy cost savings through the centralized dispatch of their committed generating resources located within the PSCo Balancing Authority Area ( BAA ). The arrangement is based on energy imbalance market concepts that FERC has previously supported, though this is a smaller scale design and is cost based rather than bid based. As part of this collaboration, a comprehensive study determined energy cost savings potential of more than $(to be determined) million for the Parties in 0. Approval of the Agreement as well as approval of proposed changes to the applicable transmission tariffs (filed contemporaneously with this Agreement) is necessary to achieve these energy cost savings through greater dispatch efficiencies. Further, the Agreement is not intended to be 0 exclusive to the initial signatories, rather it provides for expanded participation; and, the Agreement does not adversely impact any customers of the Parties, any other parties, or the customers of any other parties. III. REASONS FOR THE AGREEMENT Q. PLEASE DEFINE JOINT DISPATCH. A. Joint dispatch is similar in some ways to a small-scale energy-only imbalance market construct, designed to improve operational efficiency within the PSCo

5 Page of 0 BAA through better real-time (i.e., minute by minute) dispatch optimization of the generation resources of the Parties to the Agreement. Q. CAN YOU EXPAND ON THE PURPOSE OF THE AGREEMENT? A. The Agreement will provide the Parties the opportunity to capture intra-hour dispatch efficiencies and achieve energy cost savings. This is made possible through coordination of the Parties committed generation resources to serve the Parties aggregate electric load requirements. A Party will be able to purchase energy under the Agreement at a rate that is less than what it would cost to produce it using their own resources. Conversely, energy sales will be generated for those that are able to increase the output of their resources beyond their own needs to provide cost-effective energy to serve another Party s load. Q. HOW DOES THE AGREEMENT WORK TO CAPTURE EFFICIENCY? A. The Agreement captures efficiencies through centralized, coordinated dispatch of generation. When more efficient and lower cost generation committed from one Party is available to offset more expensive generation of another Party during the same operating hour, there are resulting efficiencies. When the energy resources of the Parties are pooled to optimally serve the aggregate demand, common economic dispatch principles yield savings through coordinated dispatch of generation resources. Greater efficiencies are captured over a larger footprint. Q. WHAT ELECTRIC LOAD DOES THE AGREEMENT COVER? A. The Agreement covers the Parties electric load within the PSCo BAA. Q. WHAT ARE THE PARTIES RESPONSIBILITIES UNDER THE AGREEMENT?

6 Page of A. First and foremost, each Party must commit sufficient generation resources to meet their own energy requirements during each hour, just as they do under today s operations paradigm. Put another way, each Party must be able to cover its native load, plus Operating Reserves, in addition to the net of any long-term and short-term system, and unit power, bilateral sales and purchases. Q. DOES THE AGREEMENT CHANGE PSCO s RESPONSIBILITIES AS A BALANCING AREA OPERATOR? A. No, PSCo s responsibilities for operating the BAA remain unchanged. Q. DOES THE AGREEMENT REQUIRE THE PARTIES TO COMMIT THEIR UNITS IN A NEW WAY? A. No. The Agreement is not a generation commitment arrangement, and the Parties do not intend to jointly commit their units or conduct joint electric resource planning. Each Party will commit sufficient resources to meet its own requirements. Q. HAS PSCO PREVIOUSLY SOUGHT APPROVAL OF THE JDA? A. Yes. The jurisdictional parties sought approval of the JDA and associated tariff revisions in Docket Nos. ER- and ER-. Commission rejected the proposal on two grounds. On June, 0, the First, the Commission 0 concluded that PSCo had not shown that the JDA s payment structure would result in rates that are just and reasonable because the payment structure of the JDA may create the conditions for the exercise of market power by PSCo, a mitigated entity in the PSCo BAA. Specifically, the Commission found that because PSCo proposes to compensate generating resources based on the System

7 Page of 0 Marginal Price, PSCo s own units would be compensated at a ceiling rate derived from the most expensive MW required to serve the aggregate loads of the Parties, instead of at cost-based rates. Second, the Commission concluded that market-sensitive operational and pricing information the Participants would provide to PSCo may grant PSCo s marketing function access to non-public information that is restricted under the Commission s Standards of Conduct. Q. DID PSCO SEEK REHEARING WITH FERC? A. Yes. On July, 0, XES, on behalf of PSCo, filed a request for rehearing of the June Order. In the request for rehearing, XES described the reasons that the information shared under the JDA does not implicate the Standards of Conduct and explained how the JDA is structured to achieve just and reasonable rates. Nevertheless, and without conceding its position in the rehearing request, PSCo is proposing three modifications of its original proposal to resolve the issues identified by the Commission in its June Order, the first of which is to perform an after the fact screen of the System Marginal Costs for JDA and Deficit sales made by PSCo and to cap the price PSCo receives for sales at its cost-based rate. Second, PSCo proposes to use a web portal to limit access to marketsensitive data to authorized personnel. As a result, none of the Parties merchant employees will have access to the unit cost data of JDA Participants, unless otherwise agreed by the Parties. Third, PSCo offers to provide annual reporting for the first two years of implementation to identify the resulting JDA benefits as

8 Page of well as the revenue from non-firm transmission. This is discussed in greater detail below. Although the XES request for rehearing of the June Order s findings on Standards of Conduct remains pending, there are significant customer cost savings that would result from implementation of the JDA, and, therefore, the JDA Parties have elected to revise the JDA with measures that address the Commission s concerns expressed in the June order in any event. IV. PUBLIC POLICY REASONS FOR THE AGREEMENT Q. WHY SHOULD FERC ACCEPT THE FILED AGREEMENT? A. It is my belief that FERC fully recognizes the appreciable benefits of organized energy markets. Organized markets have been slow to develop in the Western Interconnection beyond the California Independent System Operator ( CAISO ) and the western Energy Imbalance Market ( EIM ) administered by CAISO. Xcel Energy has vast experience operating in organized markets with the Southwestern Public Service ( SPS ) and Northern States Power ( NSP ) Operating Companies fully engaged in the Southwest Power Pool, Inc. ( SPP ) Integrated Marketplace ( SPP IM ) and the Midcontinent Independent System Operator ( MISO ), respectively. Xcel Energy is a proponent of organized 0 wholesale markets because organized markets reduce customer energy costs. Lacking a larger organized market option in Colorado presently, PSCo believes the Agreement is a step in the right direction to realize the energy savings demonstrated under larger scale market constructs. The potential annual benefits of the Agreement were studied and are projected to exceed (to be determined)

9 Page of 0 through lower fuel costs and possible economic sales margins. Consistent with FERC s objectives and interests, and in light of the anticipated benefits of the Agreement, we recommend FERC accept the Agreement. Q. HOW IS THE ARRANGEMENT IN THE PUBLIC INTEREST? A. The Agreement benefits Colorado electric customers through shared resources. First and foremost, the Agreement provides a more efficient platform to utilize existing generation resources to meet aggregate electric demand. Savings will be passed on to the wholesale and retail customers of the Parties. Q. DID THE COLORADO PUBLIC UTILITIES COMMISSION RECENTLY FILE COMMENTS REGARDING THE JOINT DISPATCH AGREEMENT? A. Yes. On August, 0 the Colorado Public Utilities Commission ( COPUC ) filed comments to PSCo s request for rehearing. The filed comments of the COPUC supported PSCo s request for rehearing. The COPUC also reinforced in their comments that if the Parties determined to re-file a new JDA the COPUC will support such a proposal as well, subject to an evaluation of any significant changes from the original JDA proposal. Q. DO YOU THINK THE AGREEMENT COULD CONTRIBUTE TO A BROADER ENERGY MARKET WITHIN THE PSCO BAA? A. Yes. Other utilities operating within the PSCo BAA will observe the reliable and economic operations associated with the Agreement and may desire to provide the same benefits to their customers. The Parties designed the Agreement in a See Comments of the Colorado Public Utilities Commission filed August, 0, Docket Nos. ER- -00, ER--000, ER--00 and ER--00.

10 Page of 0 manner anticipating interest and participation of other similarly situated utilities. The Parties also have discussed that it may be possible to later expand upon this design to include unit commitment and/or to further optimize operating reserve requirements of the Parties at some point in the future. At a minimum, the Agreement is recognized by the Parties as a means to gain further experience in market-like operations as they look forward to more comprehensive constructs developing in the Western Interconnect. Q. IS THE AGREEMENT OPEN TO ADDITIONAL PARTICIPANTS? A. Yes. Participation in the JDA is available on a nondiscriminatory basis. The Agreement is not limited to the current signatories; it is open to all entities that meet the eligibility criteria. As described by Ms. Eaton in a separate but companion filing, PSCo is also requesting the Commission accept Joint Dispatch Transmission Service ( JDTS ) that would be available to JDA participants at a $0 rate, and under Section. of the JDA, each JDA participant reciprocates by providing the JDTS to facilitate the transfer of JDA energy, at no additional cost, across the transmission systems where it is located. Service under the JDTS rate schedule is intended to facilitate JDA transactions. The eligibility criteria are intended to encourage the broadest possible participation by entities in the PSCo BAA. Q. WHAT CONDITIONS MUST BE MET IN ORDER TO BECOME A MEMBER OF THE JDA?

11 Page of A. Any entity that meets the conditions of the JDA can join. Greater participation under the JDA would only work to expand the pool of benefits for the JDA Parties. In order to participate in the JDA, the entity requesting to join must: be a load serving entity in the PSCo BAA; have a resource that is capable of being dispatched by PSCo on a real-time basis (which would include external resources pseudo-tied into the PSCo BAA); and must agree to implement a transmission service comparable in terms and costs to PSCo s proposed JDTS if it is a Transmission Service Provider ( TSP ), or if the entity is not a TSP itself, then it must make comparable service available through its TSP. 0 Q. WHAT IS THE BASIS FOR LIMITING PARTICIPATION TO ENTITIES WITH LOADS AND RESOURCES WITHIN THE PSCO BA? A. It is a practical necessity. The PSCo Energy Management System ( EMS ) is the primary tool that will be used to issue economic set-points to Dispatchable Units. Using the PSCo EMS limits the participation to entities with loads and resources within the PSCo BAA. Q. IF THE JDA WAS ACCEPTED BY FERC, WOULD PSCO STILL CONSIDER JOINING A LARGER ORGANIZED WHOLESALE ENERGY MARKET IF ONE WERE TO DEVELOP IN COLORADO? A. Yes. The Company has much experience operating in and remains a strong advocate for organized wholesale energy markets in general and believes that they are ultimately beneficial for customers. Participating in the JDA is a ready means

12 Page of 0 to more immediately capture some of the benefits of the larger-scale organized markets, but if a larger-scale organized market were to develop in Colorado, PSCo would evaluate the benefit to customers and likely seek to join and participate in it. The Parties contemplated this concept, and at least in part, this influenced the termination options inherent within the Agreement. Additionally, while PSCo has much experience in organized markets, the other Participants do not. The JDA provides an opportunity for the Participants to gain experience in market-like operations, which they value. Q. DO YOU BELIEVE THAT THE AGREEMENT COULD PROVIDE AN INCREASING LEVEL OF BENEFITS AS OTHER NEW PARTIES PARTICIPATE? A. Yes. In general, expanding the electric footprint and pool of dispatchable resources increases the economic benefit potential. Q. HOW DOES INVOLVEMENT IN THE AGREEMENT IMPACT EACH PARTY S ABILITY TO ENGAGE IN OTHER TRANSACTIONS, SUCH AS OFF-SYSTEM SALES? A. The Parties will still have the freedom to choose to make off-system sales in addition to or instead of contributing to the joint dispatch pool. Each party will be able to weigh their bilateral opportunities against potential joint dispatch opportunities. Regardless, even if off-system sales are prioritized, joint dispatch will provide net positive benefits for each of the Parties.

13 Page of 0 Q. FOR PSCO SPECIFICALLY, WILL JOINT DISPATCH SALES BE TREATED ANY DIFFERENTLY THAN OTHER BILATERAL, SHORT- TERM WHOLESALE SALES? A. No, the same processes and margin allocations that are currently in place for short-term wholesale sales will also apply to any sales volumes associated with the Agreement concerning both PSCo s retail and wholesale customers. Q. WILL ANY TRANSFER OF RENEWABLE ENERGY CREDITS (RECS) TO THE OTHER PARTIES OCCUR UNDER THE AGREEMENT OR WILL THIS ARRANGEMENT OTHERWISE IMPACT THE ALLOCATION OF RECS TO WHOLESALE CUSTOMERS? A. No. RECs will not be transferred under the Agreement between Parties. Only energy will be transferred under the Agreement between Parties. Additionally, the Agreement will not impact the current allocation of any Party s RECs to retail or wholesale customers. Q. ARE THERE ECONOMIC OR OPERATIONAL DISADVANTAGES FOR PARTICIPATING IN THE AGREEMENT? A. No. Having the additional options for economic dispatch optimization under the Agreement does not create a downside, though the value realized by each Party depends on the degree of involvement between the Parties. Said another way, the Parties costs will not increase under the Agreement compared to what they would have been if the Parties were dispatching resources on their own. This is because ) the administrative costs are nominal and will be less than the economic benefits provided by the joint dispatch arrangement; and ) the worst case economic

14 Page of 0 scenario for any hour would be that each Party meet its own obligations as it planned heading into the hour and at the cost of the resources it committed to serve its load. V. BENEFITS AND COSTS OF THE AGREEMENT Q. WHAT IS THE RANGE OF EXPECTED BENEFITS FROM THE PARTIES PARTICIPATION IN THE AGREEMENT? A. The Parties conducted case studies to determine the benefits of the Agreement. The case studies for the pool of benefits for the Parties are detailed in Figure below. A range of benefits is presented due to the Agreement not preventing nor hindering other transactions from occurring, as explained previously. (Dollar amounts to be determined) Q. WHAT IS THE RANGE OF EXPECTED COSTS FOR THE PARTIES PARTICIPATION IN THE AGREEMENT? A. A key objective established by the Parties was to strictly manage the overall implementation and operating costs under the Agreement. To that end, the Parties have successfully worked to control costs in the design and development of the Agreement. PSCo will bear the cost to set up the systems that will price and settle the energy exchanged under the Agreement, which PSCo anticipates to be approximately $0,000. It will be more difficult to quantify with precision the ongoing costs to support the coordinated dispatch of the pool of resources. Therefore, the Parties support a per-unit volumetric management fee in the Agreement, applied to Joint Dispatch sales and purchases to help PSCo recover both the setup and ongoing costs of operations and settlements.

15 Page of Q. PLEASE DESCRIBE THE IMPACTS OF THE JDA TO NON- PARTICIPANTS. WILL THERE BE A LOSS OF NON-FIRM TRANSMISSION REVENUES CREDITS AS A RESULT OF THE JDA? A. No. Because Parties to the JDA are required to have available sufficient resources to serve load plus reserves for every hour under Section. of the JDA, I expect little if any change to the amount of non-firm transmission service participants to the JDA will purchase from their own transmission providers or the other JDA transmission providers. In advance of the intra-hour dispatch under the JDA, Parties will not know whether their resources will be dispatched up or down in real-time. Therefore, Parties will continue to look for opportunities to lower their dispatch costs through economic purchases. Parties will also look for opportunities to lock in margins from economic sales. Transmission will have to be procured for both economic purchases and sales just as it is today. The expected de minimis impact of the JDA on PSCo transmission revenues is discussed in Ms. Eaton s testimony. VI. ELECTRIC OPERATIONS UNDER THE AGREEMENT 0 Q. WHO WILL BE RESPONSIBLE FOR THE CENTRALIZED DISPATCH OF RESOURCES UNDER THE AGREEMENT? A. PSCo will have the responsibility to perform the coordinated dispatch of the Parties participating dispatchable generation, issuing economic dispatch set points or targets to the resources. Q. HOW WILL UNITS BE ECONOMICALLY DISPATCHED?

16 Page of 0 A. Generation cost information will be provided by BHCE, PRPA and PSCo and managed in the Joint Dispatch Portal ( Portal ). That information, including heat rate, fuel prices, non-fuel variable operations and maintenance costs, and, if the unit is contracted by a Party under a Power Purchase (as defined within the Agreement), other incremental operating costs of a Party specified in the underlying Power Purchase contract will inform the economic dispatch formulas in the PSCo Energy Management System ( EMS ) to allow PSCo to determine how to economically optimize the pool of generation resources under the Agreement. Generation resources with Automatic Generation Control ( AGC ) capability will be able to receive automatic economic set-points from the EMS. Units that lack AGC capability will be dispatched manually to optimal set-point targets. All Dispatchable Units must respond to the economic set-points issued by PSCo. If units fail to respond to the economic set points then the facility will not be eligible to set the marginal price for Joint Dispatch Transactions under the Agreement. Q. WHAT ASSURANCE IS THERE THAT JDA PARTICIPANTS PROVIDE ACCURATE COST INFORMATION? A. First, the JDA requires that Unit Cost Information, as defined in Article II of the JDA, provided by the Parties to support joint dispatch be cost-based. Further, Article 0. of the JDA allows any party to audit the records of any other party to the extent reasonably necessary to verify the accuracy of any statement, charge or computation. This audit authority includes the ability to audit unit input parameters or fuel prices, including PSCo s unit input parameters or fuel prices.

17 Page of 0 Thus, authorized personnel from each Party will have access to the cost data of each other to ensure that they are performing consistent with their obligations under the JDA. Article of the JDA identifies several standing committees, including an Audit Committee tasked with performing periodic audits of operations under this Agreement, which could include audits of unit input parameters and fuel prices. Finally, to the extent that any audit identifies inaccuracies in any statement, Section 0. imposes interest on any required payment adjustments. Such inaccuracies would include errors in System Marginal Price resulting from incorrect unit parameters or fuel prices. Of these various aspects of the JDA, the audit mechanism provides a specific and critical means to ensure the accuracy of the cost data upon which exchanges take place under the JDA. Auditing is particularly important in the short run to provide verification of the cost data for specific transactions. But the auditing process as a means to ensure cost accuracy is reinforced by the nature of the JDA. The principal reason that parties to the JDA can rely on the cost data they exchange is that accurate cost data is the mechanism by which the Agreement achieves the Parties underlying objectives, and the Agreement could not work in the long-term if that information was not accurate. Q. WHICH UNITS WILL BE DISPATCHED UNDER THE AGREEMENT? A. Only Dispatchable Units, as defined in the Agreement, will be dispatched by PSCo. Dispatchable Units are owned or purchased generation resources electrically located in the PSCo BAA that are designated by the Parties. BHCE

18 Page of 0 and PRPA retain flexibility as to which units they choose to have participate. PSCo will designate all of its dispatchable generating resources that are online and electrically located in its BAA as Dispatchable Units. Q. ARE ALL UNITS OWNED OR PURCHASED BY A PARTY INCLUDED AS DISPATCHABLE UNITS UNDER THE AGREEMENT? A. No. Generating resources must be specifically identified as Dispatchable Units by the Participants, at their discretion. Q. CAN GENERATING UNITS BE DESIGNATED AS DISPATCHABLE UNITS AFTER THE AGREEMENT IS EXECUTED? A. Yes. BHCE and PRPA may inform PSCo whether a unit is a Dispatchable Unit or not on an hourly basis. Q. CAN NEWLY CONSTRUCTED UNITS OF THE PARTIES BE INTEGRATED AND OPTIMIZED UNDER THE AGREEMENT? A. Yes. A Party will give notice at least two months prior to the beginning of a month in which a new Party Resource, as defined under the Agreement, will be available for use as a Dispatchable Unit under the Agreement. The notice will allow PSCo to set up and integrate the resource into the EMS to enable optimization of the resource in conjunction with other resources within the joint dispatch operating pool. Q. WILL THERE BE ANY COORDINATION FOR THE NEXT-DAY OR HOURLY PLANNING UNDER THE AGREEMENT? A. Yes, but this is primarily a continuation of each Party s existing responsibilities as Load-Serving Entities. The level of coordination and short-term electric

19 Page of reliability planning to ensure sufficient resource capability within the BAA already exists and is unchanged by the Agreement. The Parties will continue their normal day-to-day processes to manage their fleet of resources to ensure reliable and economic operations for the next day(s) and hours. The Participants must be able to demonstrate that they planned to have sufficient resources committed to serve their own obligations, but this validation will take place in post-analysis rather than forward-looking resource adequacy evaluations. In cases where 0 insufficient resources are demonstrated, Surplus or Deficit Energy settlement pricing is applied, as described in Section VII. Further, as described below, the Agreement replaces settlement of Imbalance Energy under Schedules and of the PSCo Open Access Transmission Tariff ( OATT ) for Participants. Q. HOW WILL THE TRANSMISSION FOR JDA TRANSACTIONS BE PROVIDED? A. The necessary transmission for JDA transactions will be provided by Joint Dispatch Transmission Service, which is a non-firm, as-available transmission service provided at a zero rate that is made available for the sole purpose of facilitating energy transfers pursuant to the JDA. This service is discussed more fully in a separate, concurrent filing seeking approval of the Joint Dispatch Transmission Service supported by the testimony of Ms. Eaton. As reflected in Sections. and. of the JDA, JDA transactions will be limited by the amount of ATC on the system operated by the transmission providers for each Party and energy flows will be limited intra-hour to the updated ATC posted by each transmission provider. Although Joint Dispatch Transmission Service is a non-

20 Page 0 of 0 firm transmission service, it is a lower quality service than normal non-firm transmission under the OATT because it is available only to the extent there is ATC after all other firm and non-firm transmission uses are taken into account. Joint Dispatch Transmission Service is provided from ATC that would otherwise go unused. Q. WILL THERE BE A NEED TO E-TAG JDA TRANSACTIONS? A. With a limited exception, no. Unscheduled flows on Qualified Paths within the Western Interconnect are monitored through the Unscheduled Flow Mitigation Procedure ( UFMP ) and curtailments may be issued to relieve the impact of loop flows on such paths, but none of the Qualified Paths are located in the PSCo BAA. The exception is where the sale of Joint Dispatch Energy from certain generators that have been identified as having a transmission distribution factor equal to or great than percent on Western Electricity Coordinating Council ( WECC ) Qualified Paths, as referenced in the WECC UFMP. There are two generating stations which JDA members have partial ownership that are identified as having greater than percent impact on WECC Qualified Paths 0 and : Craig and Hayden. Energy scheduled by PSCo from Craig, a generating station that is located in the Western Area Colorado Missouri ( WACM ) BAA, will be scheduled and tagged based on the anticipated needs of the PSCo system to serve native load customers, using firm network transmission service. No changes are planned for Craig under the JDA and Craig will not be available to set marginal pricing and provide JDA sales.

21 Page of Hayden is a generating station that is pseudo-tied in to the PSCo BAA. PSCo has a MW share of unit and a MW share of unit. PSCo s share of Hayden is and will continue to be tagged in compliance with NERC Standard INT-00-., which is applicable to dynamic transfers. PSCo will issue one tag for output from Hayden that is intended to serve network load using network transmission service. potential JDA sales. PSCo will issue another tag for capacity available for 0 Tagging JDA transactions from Hayden allows these low priority transactions to be curtailed to manage congestion when necessary. This allows these schedules to be visible and monitored for congestion management under the UFMP and allow for proper prioritization of necessary schedule curtailments to be based on their transmission service type. The transmission associated with JDA sales tag will have a priority of 0 so that it will be the first to be cut in the event of a curtailment event. The combined volumes of both tags will not exceed the amount of ATC assigned to PSCo for network service from Hayden. It is my understanding that PRPA plans to implement a process similar to the one detailed just above concerning Hayden and will tag energy from their ownership of Craig into the PSCo BAA (i.e. issue one tag that is intended to serve their customers and another tag for capacity available for potential JDA sales). Below is a schematic identifying how the tagging for deliveries from Hayden will function. The red line represents the tag for service to network customers. On OASIS it will be a firm network reservation equal to the anticipated needs for native load customers. The blue line represents the tag for

22 Page of JDA service and would show in OASIS as a zero priority service and would be the Hayden capacity minus the schedule volume of the Network Tag, assuming available ATC. For example if Hayden Unit is fully available but only 0 MW is needed to serve PSCo native load customers for the next hour, the tag for the red line should be 0 MW for each leg (Hayden to Craig, Craig to TOTW, and TOTW to PSCo) and the blue line would use the posted ATC up to MW with a zero priority service for each of the three legs. HDN PSCo Share (Unit ) MW Tag associated with native service CRG Tag for 0 MW (FN) Tag associated with JDA MW Tag (0-NX) TOTW 0 MW for Native PSCO VII. PRICING UNDER THE AGREEMENT Q. IS THE ENERGY PROVIDED UNDER THE AGREEMENT PRICED BEFORE IT IS TRANSFERRED? A. No. Energy under the Agreement is priced on an ex post basis. In other words, the pricing for the energy is determined after it is delivered within the PSCo BAA.

23 Page of Q. IS ALL ENERGY PROVIDED UNDER THE AGREEMENT PRICED UNIFORMLY? A. No. The energy is priced based on its classification as Joint Dispatch Energy, Deficit Energy, or Surplus Energy. Q. HOW ARE THESE CLASSIFICATIONS MADE ON AN EX POST BASIS? A. The energy is classified based upon whether or not the Parties have enough generation with the flexibility to serve and balance their Energy Requirements defined under the Agreement. Joint Dispatch Energy is economic energy 0 delivered under normal Joint Dispatch operations. Energy is classified as Deficit Energy only when a Participant commits insufficient resources to meet its own requirements, as is required by the Agreement, and thus may have its resources supplemented by PSCo. Similarly, a Participant that does not have the flexibility to reduce its resources to balance to its Energy Requirements will sell the excess energy under the terms defined for Surplus Energy. Deficit Energy and Surplus Energy replace the energy imbalance services currently offered under the PSCo OATT. Q, HOW MUCH ENERGY DO YOU EXPECT WILL BE JOINT DISPATCH ENERGY COMPARED TO DEFICIT AND SURPLUS ENERGY? A. The vast majority of energy exchanged under the Agreement is expected to be Joint Dispatch Energy for all Parties. The Agreement establishes that the Parties must commit sufficient generation to meet their own Capacity Requirements, defined under the Agreement as the Native Load, plus Operating Reserves, plus

24 Page of 0 the net of any long-term and short-term system, and unit power, bilateral purchases and sales. Q. HOW IS JOINT DISPATCH ENERGY PRICED? A. Joint Dispatch Energy is priced on a per MWh basis at the System Marginal Price. System Marginal Price under the Agreement is the most costly MW required to serve the aggregate loads of the Parties based on the hourly Unit Incremental Cost of Dispatchable Units that are online and operating above their minimum economic dispatch limit. This price will never be less than $0/MWh. The pricing calculation is determined on an hourly basis utilizing actual integrated generation production, incremental heat rates, and fuel costs plus any non-fuel variable operations and maintenance costs, and, if the unit is contracted by a Party under a Power Purchase, other incremental operating costs of a Party specified in the underlying Power Purchase contract. Q. HOW IS INCREMENTAL COST DETERMINED IN THE SYSTEM MARGINAL PRICING METHODOLOGY? A. The incremental cost is calculated based on a second order polynomial heat rate curve provided by the Party for their generators and the applicable variable operating and maintenance costs and fuel price. Q. DID THE JDA PARTICIPANTS CONSIDER A SHARE-THE-SAVINGS PRICING METHODOLOGY? A. Yes, however, the modeling for multiple parties under a share-the-savings pricing methodology is significantly more complex and the pricing is far less transparent. Compounding that concern is the fact that if other parties join the JDA the

25 Page of 0 modeling complexity increases exponentially. The Parties considered this pricing methodology but opted against it due to the modeling complexity and the lack of transparency. Q. HOW ARE DEFICIT ENERGY AND SURPLUS ENERGY PRICED DIFFERENTLY? A. First, Deficit Energy and Surplus Energy will only apply to the volume of energy exchanged that is not designated as Joint Dispatch Energy. Deficit Energy will be based on the energy costs PSCo incurs to provide and supply the Energy Requirements of the Participant that does not have adequate resources to serve their obligations, plus the greater of $/MWh or percent of PSCo s costs for providing the Deficit Energy. Surplus Energy is priced on a per MWh basis at the System Marginal Price used for Joint Dispatch Energy, less one dollar per megawatt-hour. However, an applicable tolerance band, defined as either the Surplus Energy Tolerance or Deficit Energy Tolerance under the Agreement, will afford some additional Economic Dispatch Limit flexibility for Participants. The tolerance band essentially expands Joint Dispatch Energy pricing for an additional. percent of the Participants Energy Requirements. This functions similarly to the tolerance band inherent within Schedule and of the pro-forma OATT. Both the charge for Surplus Energy of $/MWh and the charge for Deficit Energy of $/MWh or percent of PSCo s costs for providing the Deficit Energy are intended to operate as penalties, and are not cost-based rates. The levels of these penalties were mutually-agreed upon among the JDA parties. It is

26 Page of 0 my understanding that the Commission has previously explained that penalties generally are not cost-based and therefore cost-based support is not required. Q. WILL THE PROPOSED SURPLUS/DEFICIENT ENERGY PRICING UNDER THE JDA CREATE PERVERSE INCENTIVES? A. No. There is no perverse incentive that a JDA Parties would over- or undersupply energy under the JDA. There is no reason to presume that Parties will exploit the JDA for reasons other than its intended purposes. If a Party were to continually and repeatedly oversupply energy under the JDA, PSCo would consider such activity to constitute a breach of the JDA. Section. of the JDA states that [i]t is the responsibility of each Party to have capacity on-line sufficient in quantity and operating characteristics, such as ramp rate and economic minimums and maximums, to reliably serve that Party s Capacity Requirements. Nevertheless, if a Participant did make a decision to intentionally oversupply in order to profit from a cost difference and the penalty, no harm would accrue to anyone other than that Party because the over-supplied energy would still be provided at less cost than the next available unit. As stated in section.. of the JDA, Deficit Energy will be priced on a per MWh basis at PSCo s cost to provide the energy, including any start costs or no load costs, plus the greater of $ per megawatt-hour or percent of such cost to provide the energy. Section.. provides that Surplus Energy will be priced on a per MWh basis at the System Marginal Price, less one dollar per megawatt-hour.

27 Page of 0 VIII. BILLING AND PAYMENTS UNDER THE AGREEMENT Q. WHICH PARTY IS RESPONSIBLE FOR DETERMINING EX POST PRICING AND PAYMENT? A. PSCo will issue settlement statements including the energy quantities delivered among the Parties and the applicable prices for those sales to determine the proper billing amounts. However, the Participants will be provided transparency into the pricing and settlement processes by way of daily reports that will be issued by PSCo and dispatch logs relating to the dispatch of Dispatchable Units under the Agreement. Additionally, the Parties have audit rights under the Agreement. Q. HOW DOES PSCO SETTLE THE QUANTITIES DELIVERED UNDER THE AGREEMENT? A. First, PSCo will issue a daily report to the Parties on the next business day after the close of the Operating Day. These reports are inputs into the settlement procedure conducted by PSCo, which unfolds in two steps: ) In the Initial Settlement phase, statements are issued by PSCo seven days after the close of the Operating Month. The Initial Settlement reflects all daily reports issued that Operating Month and the amounts due or owed by each Party; ) In the Final Settlement phase two months after the end of the operating month, PSCo makes any necessary adjustments to the Initial Settlement and issues to each Party a summary of the final amounts owed. Q. WHAT DOES THE AGREEMENT SPECIFY CONCERNING BILLING? A. The Agreement specifies that the accounting and billing period for transactions under this Agreement shall be one () calendar month. Parties shall bill and pay

28 Page of 0 one another directly. Bills will be issued by any Party to another Party by the th day of the month after the end of the Operating Month. Payments for amounts invoiced under this Agreement shall be made by the Party by the close of business on the 0 th day of the month or the th day after receipt of the bill, whichever is later. Q. WHAT PROVISION DOES THE AGREEMENT MAKE TO ADDRESS ERRORS IN DISPATCH? A. The JDA provides generally that errors in dispatch will not be adjusted except in very limited situations. Specifically, to the extent that a data transfer error occurs and information input into the Portal by a Party does not migrate to the EMS in a timely manner, the cost of that data migration error will be shared equally among all Parties where: () the error was reported within three business days; and () the impact to an individual Party exceeds $0,000 across all hours of the operating day. It is important to note that the Parties believe this situation is very unlikely to arise. In the event any Participant becomes uncomfortable with the manner in which dispatch is occurring, they have the ability to simply remove their load and resources from joint dispatch until their concerns are resolved. Q. IS PSCO COMPENSATED FOR SETTING UP THE SYSTEMS TO PRICE AND SETTLE THE ENERGY SALES UNDER THE AGREEMENT AND FOR UNDERTAKING THE DISPATCH OPTIMIZATION RESPONSIBILITIES?

29 Page of 0 A. Yes. As per Exhibit A of the Agreement, PSCo will receive a management fee from the Participants at a rate of $.0/MWh for all energy purchased and sold under the Agreement. Q. HOW WAS THE MANAGEMENT FEE OF $0.0/MWh DETERMINED? A. The $.0/MWh management fee was mutually agreed-upon by the Parties. The purpose of the fee is to recover a contribution from the other Parties to the incremental costs that PSCo will be incurring to implement the JDA. The PSCo merchant function will provide the services associated with the provision of Joint Dispatch service and will bear the implementation costs of the JDA (described further below), and the management fee will offset a portion of the costs that the PSCo merchant function (and ultimately its production customers) must bear. However, the actual costs that will be incurred by PSCo in implementing the JDA cannot be fully quantified at this time with any level of precision. Therefore, the $0.0/MWh management fee is proposed as a hard-to-quantify adder, which I understand FERC has accepted in the past. Q. PLEASE DESCRIBE THE ACTIVITIES THAT THE MANAGEMENT FEE IS DESIGNED TO RECOVER. A. The activities associated with management of the JDA will be incurred by PSCo s Commercial Operations and its Business Systems organization. PSCo s Transmission function will incur only de minimis costs as a result of implementation of the JDA (due primarily to administering Joint Dispatch Transmission Service agreements) and therefore neither additional costs nor revenues associated with the JDA will be allocated to Transmission. The

30 Page 0 of 0 Transmission function s role in the JDA is discussed further in testimony of Ms. Eaton. Q. WHAT ACTIVITIES WOULD THE BUSINESS SYSTEMS ORGANIZATION PERFORM FOR THE JDA? A. Incremental increases in activity or investment to support the JDA will occur in the Business Systems organization, which is a support organization that provides information technology ( IT ) services to the Xcel Energy operating companies, including PSCo. The Business Systems organization is not a part of PSCo s Transmission or Commercial Operations. The Business Systems organization will incur two types of costs in supporting the JDA capital costs and operation and maintenance expense. The capital costs associated from the JDA will be for creating a new Portal to capture and manage JDA unit operating data and settlements data; and incorporating SCADA data feeds for BHCE and PRPA units into the Energy Management System ( EMS ) and Integrated Energy Management ( IEM ) system. Business Systems will also incur Operation and Maintenance expenses. On an as-needed basis, the Business Systems organization will incur costs associated with: () programming and tuning into the EMS of BHCE and PRPA units that are Automatic Generation Control (AGC) capable; () updating the EMS and the IEM as BHCE and PRPA units are added or removed from JDA participation in the future; and () general maintenance of the Portal.

31 Page of 0 PSCo s participation in the JDA is not a driver of these Business Systemsrelated costs because PSCo s units are already embedded in its EMS and IEM. Because none of these costs are incurred to facilitate PSCo s participation in the Agreement, costs associated with Business Systems should not be charged to PSCo through the management fee. PSCo s production customers pay the costs underlying the management fee and will benefit from the services and overall arrangement. As discussed in more detail in the testimony of Ms. Blair, a portion of the IT costs associated with implementation of the JDA are allocated to Transmission plant. We propose a credit from Commercial Operations to Transmission to ensure that Transmission customers do not bear any of the costs associated with the Joint Dispatch Service Agreement. Q. WHAT COSTS WILL BE INCURRED BY COMMERCIAL OPERATIONS TO FACILITATE THE JDA? A. Services provided by Commercial Operations in support of the JDA that benefit both PSCo and the other JDA participants include day-to-day management of the JDA. These activities can generally be described as follows: Maintenance of reports and systems; Economic dispatch of JDA Dispatchable Units; Monitoring ATC and adjusting dispatch based on ATC; Protocol creation and maintenance; Training of staff; Management of settlements; and

32 Page of JDA-related regulatory support. Q. PLEASE DESCRIBE WHERE MERCHANT FUNCTION ACTIVITIES RESIDE. A. Merchant function activities are a part of Commercial Operations, but not all Commercial Operations are merchant function. Commercial Operation costs are assigned to production. IX. MODIFICATIONS TO ORIGINAL JDA PROPOSAL Q. PLEASE DESCRIBE THE MODIFICATIONS THAT PSCO IS PROPOSING TO THE JDA. A. PSCo is proposing several modifications to the JDA to address issues raised in the June Order. First, the Commission identified concerns with PSCo not having market-based rate authority within its BAA. Specifically, the June Order noted that the Commission has accepted other joint dispatch agreements with varying payment structures, including those that split the savings equally among participants. As described above, the modeling that would be required to identify 0 the savings with multiple parties does not make this a feasible option. Instead, PSCo proposes an after-the-fact screen of the System Marginal Costs for any generation which PSCo is a seller and agrees to cap the price received at its costbased rate. The Commission noted in the June Order: In Western, the Commission found that while a ceiling rate is technically a cost-based rate, it provides the flexibility of a market based rate, and that absent authorization to sell at market-based June Order at P 0.

33 Page of 0 rates, a seller may be able to exercise market power with respect to such cost-based ceiling rate transactions. To address the Commission s concern expressed in Western, the WSPP Inc. System Agreement now includes Schedules that are specific cost-based rates for WSPP members lacking certain market-based rate authorities. For example, PSCo is a mitigated seller and lack s market-based rate authority within its BAA. As a result, sales by PSCo inside its BAA are governed by either the WSPP s Schedule Q or PSCo s Electric Coordination Service Tariff, which are PSCo s existing cost-based rate schedules, both of which have consistent pricing methods. For the JDA transactions, PSCo proposes the same solution capping its sales (both JDA and Deficit Energy sales) at the cost-based rates on file with the Commission in the WSPP s Schedule Q and PSCo s Electric Coordination Service Tariff. With this solution in place, PSCo cannot be paid other than a costbased rate, and this will eliminate concerns that the JDA will provide PSCo the flexibility of a market-based rate and thereby allow PSCo to exercise market power. The June Order also found that the Joint Dispatch Agreement requires the Parties to grant PSCo s merchant function access to non-public information that, under the Standards of Conduct, should be restricted to PSCo s transmission function. While PSCo has requested rehearing on this matter, and without prejudice to that request, PSCo proposes to create a web portal, where JDA members would input unit cost information and PSCo would restrict access to Id. at P June Order at P.

34 Page of such data to only authorized personnel. Under this process, PSCo merchant employees will not have access to unit economic data of JDA Participants, but only the resulting dispatch. Further, the JDA has been revised to provide that, absent the agreement of all Parties, personnel that serve a merchant function within their organizations will not be able to see unit cost information. This requirement necessitates the two different types of Daily Reports discussed in Article. Merchant personnel will be provided a report that shows hourly purchase and sales volumes for each Party and the corresponding System Marginal Price for the prior operating day. Non-merchant personnel of each Party will receive a more detailed report that includes Unit Cost Information and will enable non-merchant personnel to validate that system dispatch reflects unit costs. Further, Article 0 limits access to Unit Cost Information for audit purposes to non-merchant personnel, unless otherwise agreed by the Parties. These revisions will address the Commission s concern that, under the previously-proposed JDA, it is not possible to prevent PSCo s merchant function from using the commercially sensitive, non-public information to its own competitive advantage. With the process proposed in this filing, PSCo s 0 merchant function would never receive the sensitive information. However, the Parties have retained an option for merchant function personnel to change the content and distribution of Unit Cost Information if all Parties agree. Merchant function personnel generally have greater expertise in June Order at P 0.