board of directors/members committee meeting and …

BOARD OF DIRECTORS/MEMBERS COMMITTEE MEETING

and ANNUAL MEETING OF MEMBERS October 25, 2005

Inn and Spa at Loretto – Santa Fe, NM

• A G E N D A • 8:00 a.m. – 2:30 p.m. MST *

Annual Meeting of Members 1. Administrative Items .................................................................................................Mr. Jim Eckelberger

2. Corporate Governance Committee Report..................................................................Ms. Stacy Duckett

a. Election of Directors

b. Election of Members Committee Representatives

c. Board of Directors Annual Evaluation

3. Organizational Reports – 2005 Overview/2006 Outlook

a. Operations...................................................................................................Mr. Carl Monroe

b. Finance ..........................................................................................................Mr. Tom Dunn

c. Corporate .................................................................................................Ms. Stacy Duckett

d. Regulatory................................................................................................ Mr. Les Dillahunty

e. Interregional Affairs .................................................................................Mr. Charles Yeung

Adjourn for Board of Directors/Members Committee Meeting

Board of Directors/Members Committee Meeting 1. Administrative Items ................................................................................................ Mr. Jim Eckelberger

2. Regional State Committee Report.................................................................................Ms. Denise Bode

3. Compliance Committee Report ....................................................................................... Mr. Josh Martin

a. Independent Market Monitor Report ...........................................................Mr. Craig Roach

4. Finance Committee Report............................................................................................ Mr. Harry Skilton

5. Human Resources Committee Report ....................................................................Mr. Quentin Jackson

6. Strategic Planning Committee Report ........................................................................Mr. Richard Spring

7. Markets and Operations Policy Committee Report .........................................................Mr. Mel Perkins

8. Future Meetings........................................................................................................Mr. Jim Eckelberger

* The meeting times are local to the meeting site. If you are dialing in, please plan accordingly.

MINUTES NO. 40

Southwest Power Pool SPECIAL MEETING OF MEMBERS

Doubletree at Warren Place, Tulsa, OK July 26, 2005

Agenda Item 1 – Administrative Items SPP Board of Directors Chair, Mr. Jim Eckelberger, called the meeting to order at 9:01 a.m. There were 47 people in attendance representing 26 members (Attendance List – Attachment 1). Serving as proxies were: Mr. Bill Jett for Mr. Walt Yeager and Mr. David Brian for Mr. Larry Warren (Tex-La), Mr. John Butts (ETAC) and Mr. Rick Tyler (NTEC). Mr. Eckelberger asked for a motion to approve Annual Meeting of Members minutes from October 27, 2005 (Minutes 10/27/04 – Attachment 2). Mr. Richard Spring moved to approve the October 2004 minutes as presented. Mr. Michael Desselle seconded the motion, which passed unopposed. Agenda Item 2 – Corporate Governance Committee Report Mr. Nick Brown presented the Corporate Governance Committee report (CGC Recommendation – Attachment 3). Mr. Brown explained that since SPP obtained RTO approval its directors must receive approval to hold director positions at more than one public utility. Such approval was denied for Bob Schoenberger; therefore, in accordance with SPP Bylaws the CGC is charged with nominating candidates to the Membership for election to serve an unexpired term. Mr. Brown introduced Larry Altenbaumer as the candidate selected (Altenbaumer bio – Attachment 4). Following comments from Mr. Altenbaumer and questions, Mr. Altenbaumer was excused from the meeting. Mr. Jim Stanton moved to approve the CGC recommendation:

The Corporate Governance Committee nominates Mr. Larry Altenbaumer to the Membership for election to the SPP Board of Directors to serve the unexpired term for the position vacated by Bob Schoenberger.

Mr. Desselle seconded the motion, which passed unanimously. Mr. Altenbaumer was welcomed to the SPP Board of Directors. Mr. Nick Brown provided a report on the Board of Directors evaluation results (BOD Evaluation Report – Attachment 5). SPP Bylaws require that the Corporate Governance Committee coordinate an annual review of the Board of Directors. A survey was provided to the members of the Board of Directors and Members Committee, and the chairman of the MOPC. The evaluation results are a compilation of the responses received. Mr. Brown stated that these results will be used for specific items in the Strategic Plan. Mr. Brown explained that the Board of Directors is elected for rolling 3-year terms. It is therefore necessary to fill those positions with expiring terms at the end of this year. A slate of nominations from the Corporate Governance Committee will be presented at the Annual Meeting in October. Agenda Item 3 – Human Resources Committee Mr. Quentin Jackson provided the Human Resources Committee report (HR Committee Report – Attachment 6). Mr. Jackson reported that SPP engaged Towers Perrin HR Services to assess the competitiveness and structure of its compensation program for directors. Mr. Jackson offered the following HR Committee recommendation:

Maintain the current director compensation fee structure, and add a fee of $1,250 for in-person attendance plus reimbursement of travel expenses and $250 for teleconference participation in other meetings, such fee to be paid only when the director has received approval from the Chair of the SPP Board of Directors or the SPP President in advance of participation. Directors will not require pre-approval for attendance meetings of committees reporting to the SPP Board of

Directors including; Markets and Operations Policy Committee, Regional State Committee, Strategic Planning Committee, Human Resources Committee, Finance Committee, Corporate Governance Committee, and Compliance Committee. This new schedule would be effective upon approval of the SPP membership.

Mr. Harry Dawson moved to approve the recommendation to change director compensation but make it retroactive to January 1, 2005. Mr. Doug Henry seconded the motion. The motion passed unopposed. Adjournment With no further business, Mr. Eckelberger adjourned the Special Meeting of Members at 9:40 a.m. Stacy Duckett, Corporate Secretary

Southwest Power Pool, Inc. CORPORATE GOVERNANCE COMMITTEE

October 10, 2005

NOMINATIONS TO FILL EXPIRING TERMS

Background Representatives on the Board of Directors and Members Committee serve 3-year terms. To achieve the initial staggering of terms, seats were assigned one, two and three-year terms. The one-year term positions expire at the end of 2005. Analysis The Corporate Governance Committee is responsible for nominating candidates for the Board of Directors and the Members Committee to the Membership for consideration and election at the Annual Meeting of Members. The committee is to notify the President of the specific candidates at least one month prior to the October meeting and publish the ballots to the Membership. The President is to issue the ballot at least two weeks in advance of the meeting. The elections will be held at the Annual Meeting of Members on October 25. As noted on the attached ballot, the following are nominated for 3-year terms: Board of Directors: Josh Martin

Larry Altenbaumer Members Committee (sector): Harry Dawson (municipals)

Mel Perkins (IOU) Steve Parr (Cooperatives) Walt Yeager (IPP/Marketer)

Other nominations may be made from the floor. Two positions on the Members Committee will remain vacant as there are no members in the sectors at this time: Large Retail Customer member and Public Interest/Alternative Power member. Action Requested Conduct of the elections at the Annual Meeting of Members on October 25.

Southwest Power Pool ANNUAL MEETING OF MEMBERS

October 25, 2005

Ballot for SPP Annual Elections

SPP BOARD OF DIRECTORS:

Recommended by Corporate Governance Committee: Josh Martin Larry Altenbaumer

Additional Nominees:

____________________________________ ____________________________________

SPP MEMBERS COMMITTEE:

Each Member should vote for the number of nominees allocated for each sector.

Investor Owned Utilities: (All members should vote for 1 nominee)

Recommended by Corporate Governance Committee: Mel Perkins (OG+E)


____________________________________ ____________________________________

Cooperatives: (All members should vote for 1 nominee) Recommended by Corporate Governance Committee:

Steve Parr (KEPCo)

Additional Nominees: ____________________________________ ____________________________________

Ballot for SPP Members Committee October 25, 2005

Municipals: (All members should vote for 1 nominee) Recommended by Corporate Governance Committee:

Harry Dawson (OMPA) Additional Nominees:

____________________________________ ____________________________________

IPPs/Marketers: (All members should vote for 1 nominee)

Recommended by Corporate Governance Committee: Walt Yeager (Cinergy)


____________________________________ ____________________________________

Large Retail Customer: There are currently no members in this sector.

Alternative/Public Interest: There are currently no members in this sector.

MEMBER: _________________________________ REPRESENTATIVE’S SIGNATURE: ________________________________

Southwest Power PoolSchedule of Long-Term Obligations & Member Withdrawal Obligations

Office Lease Commitment 4,179,089 Xerox Lease Commitment 169,239 7.50% Senior Notes (outstanding principal balance) 15,000,000 7.50% Senior Notes (remaining interest to maturity) 1,734,375 4.78% Senior Notes (outstanding principal balance) 25,000,000 4.78% Senior Notes (remaining interest to maturity) 4,580,830 OATI RTO_SS 756,000 Accenture COS 5,143,520 TOTAL LONG-TERM OBLIGATIONS as of September 30, 2005 56,563,053

Member Pro Rata Share Withdrawal Obligation 2004 Net Energy For LoadAmerican Electric Power - PSO 7.9629% 4,504,086 18,009,056American Electric Power - SWEPCO 8.2629% 4,673,725 18,737,020Aquila, Inc. - MPS and STJO 3.6997% 2,092,674 7,661,047Aquila, Inc. - WPK 1.7071% 965,613 2,824,531Aquila, Inc.-STJO 0.5435% 307,408 Aquila Power 0.5435% 307,408 Arkansas Electric Cooperative Corporation 1.8929% 1,070,665 3,275,336Board of Public Util.,Kansas City,KS 1.5741% 890,365 2,501,624Calpine Energy Services, L.P. 0.5435% 307,408 Cargill Power Markets, LLC 0.5435% 307,408 Cinergy Corporation 0.5435% 307,408 City of Clarksdale, Mississippi 0.6216% 351,588 189,590City of Lafayette, Louisiana 1.3289% 751,690 1,906,533City Power & Light, Independence,Missouri 0.9954% 563,053 1,097,040City Utilities, Springfield,Missouri 1.7929% 1,014,106 3,032,628CLECO Power LLC 4.6341% 2,621,185 9,929,029Constellation Energy Commodities Group, Inc. 0.5435% 307,408 Coral Power LLC 0.5435% 307,408 Duke Energy Trading & Marketing 0.5435% 307,408 Dynegy Marketing & Trade 0.5435% 307,408 East Texas Electric Coop., 1.1619% 657,201 1,501,054 Edison Mission Marketing & Trading, Inc. 0.5435% 307,408 El Paso Merchant Energy, LP 0.5435% 307,408 Empire District Electric Company 2.5919% 1,466,078 4,972,159Entergy Services, Inc. 0.5435% 307,408 Exelon Power Team 0.5435% 307,408 Grand River Dam Authority 2.1699% 1,227,378 3,947,834Kansas City Power & Light Company 6.7171% 3,799,421 14,985,152Kansas Electric Power Coop. (KEPCo) 1.2386% 700,575 1,687,185Louisiana Energy & Power Authority 1.0054% 568,683 1,121,201Midwest Energy, Inc. 1.0586% 598,756 1,250,250Northeast Texas Electric Cooperative 1.3372% 756,355 1,926,551 NRG Power Marketing, Inc. 0.5435% 307,408 Oklahoma Gas & Electric Company 11.5838% 6,552,133 26,797,765Oklahoma Municipal Power Authority 1.4828% 838,695 2,279,893Public Service Company of Yazoo City, MS 0.5912% 334,398 115,820Redbud Energy, L.P. 0.5435% 307,408 Southwestern Public Service Company 10.7236% 6,065,578 24,709,830Sunflower Electric Power Corp. 1.6870% 954,220 2,775,640Tenaska Power Services Company 0.5435% 307,408 Tex-La Cooperative of Texas 0.5919% 334,791 117,507 TXU Energy Trading Company 0.5435% 307,408 Westar Energy-(KGE&KPL) 8.7676% 4,959,197 18,642,888Western Farmers Electric Cooperative 3.0364% 1,717,502 6,051,085Williams Power Company, Inc. 0.5435% 307,408 TOTAL 1.0000 56,563,055 182,045,248

Southwest Power Pool BOARD OF DIRECTORS/MEMBERS COMMITTEE MEETING

Doubletree at Warren Place – Tulsa, OK July 26, 2005

- Summary of Action Items -

1. Approved minutes of the April 26 and June 10, 2005 Board of Director/Members Committee meetings.

2. Approved the Human Resources Committee’s recommendation of funding of the SPP Retirement Plan at $979,000 and the SPP Post-retirement Benefits Plan at $471.200 but amended the amounts to $1,075,791 and $504,000 respectively.

3. Approved the Human Resources Committee’s recommendation to provide a supplemental executive

retirement plan (SERP) compliant with section 457(b) of the Internal Revenue Code.

4. Approved the Markets and Operations Policy Committee recommendation to implement the Energy Imbalance Service Market May 1, 2006.

5. Approved an amended Markets and Operations Policy Committee’s regional transmission definition:

All existing non-radial power lines, substations, and associated facilities, operated at 60 kV or above, plus all radial lines and associated facilities operated at or above 60 kV that serve two or more eligible customers not Affiliates of each other. All facilities operated at 60 kV and above constructed in the future would be included.

6. Approved Markets and Operations Policy Committee’s recommendation for Tariff modifications to: Schedule 1, Attachment L, and Attachment AA necessary to specify an “unpancaked” scheduling charge and provide for the distribution of revenue between multiple entities owning transmission facilities in a single zone.

7. Approved the Strategic Planning Committee’s recommendation to adopt the Strategic Plan 2005 and

authorize the delegation of responsibilities to SPP organizational groups under the coordination oversight of the Strategic Planning Committee and the Markets and Operations Committee to carry out the plan.

9. Approved the Strategic Planning Committee’s recommendation to approve the necessary SPP Bylaws and

Membership Agreement amendments to waive the withdrawal obligation related to long-term commitments and future interest for large retail customer Members, small retail customer Members, and alternative power/public interest Members so long as the entity is not a market participant

10. Approved the Entergy ICT Business Plan Proposal and granted the authority to execute the documents

necessary to develop this project.

11. Approved the Corporate Governance Committee’s nomination of Larry Altenbaumer to replace Bob Schoenberger on the Finance Committee.

12. Approved the Finance Committee’s recommendation increasing the 2005 capital budget to $18.3M from

the previously approved level of $12.8M.

MINUTES NO. 100

Southwest Power Pool BOARD OF DIRECTORS/MEMBERS COMMITTEE MEETING

Doubletree at Warren Place, Tulsa, OK July 26, 2005

Agenda Item 1 - Administrative Items SPP Chair Mr. Jim Eckelberger called the meeting to order immediately following a Special Meeting of Members (Agenda – Attachment 1). The following Board of Directors/Members Committee members were in attendance, via teleconference, or represented by proxy:

Mr. Larry Altenbaumer, director Ms. Phyllis Bernard, director Mr. Nick Brown, Southwest Power Pool Mr. David Christiano, City Utilities of Springfield, MO Mr. Harry Dawson, Oklahoma Municipal Power Authority Mr. Michael Desselle, American Electric Power Mr. Jim Eckelberger, director

Mr. Kevin Easley, Grand River Dam Authority Ms. Trudy Harper, Tenaska Power Services Company Mr. Doug Henry, Westar

Mr. Quentin Jackson, director Mr. Joshua Martin, director Mr. Mike Palmer, Empire District Electric Company Mr. Steve Parr, Kansas Electric Power Cooperative Mr. Gary Roulet, Western Farmers Electric Cooperative Mr. Harry Skilton, director Mr. Richard Spring, Kansas City Power & Light Mr. Jim Stanton, Calpine Mr. David Brian, for Mr. Rick Tyler, Northeast Texas Electric Cooperative Mr. Gary Voigt, Arkansas Electric Cooperative Corporation

Mr. Bill Jett, for Mr. Walt Yeager, Cinergy Corporation There were 47 persons in attendance representing 26 members (Attendance List - Attachment 2). Mr. Brown reported proxies and a quorum was declared (Proxies - Attachment 3). Mr. Eckelberger asked for a round of introductions. Mr. Eckelberger referred to draft minutes of the April 26 and June 10, 2005 meetings and the asked for corrections or a motion for approval (4/26/05, 6/10/05 Meeting Minutes - Attachment 4). Ms. Bernard moved that the minutes be approved as presented. Mr. Skilton seconded the motion, which passed. Agenda Item 2 – President’s Report Mr. Nick Brown presented the President’s Report (Quarterly Report – Attachment 5). Mr. Brown highlighted several items in the Quarterly Report including the rise in TLR events over last year. He stated that the number of TLRs is being evaluated to see what is influenced by the market implementation. Ms. Harper requested that information be sent via email regarding how many TLRs were called by Southwest Power Pool versus other reliability coordinators. In addition to the Quarterly Report, Mr. Brown provided updates on administration, regulatory, operations and interregional issues (President’s Report to BOD – Attachment 6). The administration items noted were:

• SPP Staff currently includes 145 full time employees, 1 intern and one part-time employee. Additional

SPP Board of Directors/Members Committee Minutes July 26, 2005

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year-to-date statistics were given. • Architectural drawings for the new operations center were on display for review. It is expected to be

operational prior to summer 2006. • Energy imbalance service market training is organized into four training tracks including Markets for IT,

Operations/Trading, Scheduling, and Settlements. The training department has conducted market training classes for approximately 350 people since January of 2005.

• Mr. Brown announced that with the Board’s encouragement he applied and has been accepted to Harvard Business School’s Advanced Management Program. The program runs September 11 - November 4, 2005. Carl Monroe and the SPP officers will be responsible for SPP during that time.

Regulatory items reviewed:

• Commissioner Joseph Kelliher was appointed chairman of FERC replacing Pat Wood. Chairman Kelliher appointed Dan Larcamp as Commission Chief of Staff and Shelton Canon to head the Office of Markets Tariffs and Rates.

• Comments and protests to SPP’s energy imbalance market tariff filing were due July 15th. It is hopeful an order will come in early September.

Operations items:

• Implementation of the MISO JOA is proceeding on schedule for an October 1, 2005 implementation of coordination on flowgates.

• The SPP Reliability Coordinator had a Readiness Audit conducted by NERC. • The transmission facilities of Aquila’s three operating companies, Missouri Public Service Co., St. Joseph

Light & Power and West Plains Energy, were added to the SPP regional tariff July 1. • Staff is working on the first ever Aggregate System Impact Study. They are on tract for achieving a study

publication in the first week of August. Interregional Issues:

• COMPETE, a national coalition promoting the public interest benefits of competitive electricity markets, released a new study last week showing considerable consumer savings from 1999 – 2003 stemming from wholesale electric market competition.

• The ISO/RTO Council is nearing completion of a white paper detailing the benefits of regional transmission organizations.

Agenda Item 3 – Regional State Committee Report RSC President, Denise Bode presented the Regional State Committee (RSC) report via phone. Commissioner Bode stated that the RSC has filed comments on the long-term transmission rights signed by all states with the exception of Texas. There was an RSC conference call on July 7 at which Mike Proctor reviewed the transmission definition. The consensus of the RSC was that of support. Ms. Bode added that the RSC would discuss the following items at their meeting July 27: large generation interconnection agreements; status of the cost benefit study; the energy imbalance market; a presentation on confidentiality and its issues and impacts on the RSC; the RSC budget; and the RSC audit arranged for by Commissioner Sandy Hochstetter. Commissioner Bode requested that in the future, hard copies of the Board of Director’s background material be distributed to the RSC. Agenda Item 4 – Finance Committee Report Mr. Harry Skilton presented the Finance Committee report. Mr. Skilton stated that the next Finance Committee meeting is to be held on August 11 in Dallas. The agenda will include the directors and officers insurance and a discussion of, the SAS70 Audit with Price Waterhouse. The committee is resolved to file the credit policy with the October filing.


4

Mr. Skilton reported that the Credit Task Force is gathering credit profiles from the members and customers. Every member and customer will be scored. It is the goal to have all scoring completed and the results communicated to all profiled by August 31, 2005. The results will be posted on the OASIS site. Ms. Harper requested that filing of the Credit Policy be held off as long as possible. Mr. Tom Dunn stated that the Credit Policy will be filed in October with the EIS Market Tariff changes. Agenda Item 5 – Human Resources Committee Report Mr. Quentin Jackson provided a Human Resources Committee (HRC) report. Mr. Jackson stated that the committee met on Monday, July 25. Discussion included a review of the SPP benefit plan and the employee compensation plan. The committee decided that a 4% cost of living raise would be applied to SPP employees in 2006. The committee also is outlining an incentive compensation plan in which all employees may participate. Details of this plan will be presented at the October Board of Directors meeting. Mr. Jackson provided background on the SPP Retirement Plan and the SPP Post-Retirement Plan (Retirement Plan Recommendation – Attachment 7). Mr. Jackson moved that the Board of Directors: Approve 2005 funding of the SPP Retirement Plan at $979,000. Approve 2005 funding of the SPP Post-retirement Benefits Plan at $471,200. Mr. Altenbaumer seconded the motion. Mr. Skilton moved to amend the recommendation to contribute the maximum level of $1,075,791 and $504,000 while possible. Ms. Bernard seconded the amendment. The Members were unanimous in favor. The motion passed. A vote was called for the amended motion. The Members were unanimous in favor. The motion passed. Mr. Jackson provided background on the supplemental executive retirement plan (SERP Recommendation and Plan Document – Attachment 8). The HRC developed a draft SERP compliant with section 457(b) of the Internal Revenue Code. Mr. Jackson moved to approve the following recommendation:

The Human Resources Committee recommends SPP establish a supplemental executive retirement plan in substantially the form discussed above and detailed in the attached plan document.

Ms. Bernard seconded the motion. The Members were unanimous in favor. The motion passed. Agenda Item 6 – Markets and Operations Policy Committee Report Mr. Mel Perkins presented the Markets & Operations Policy Committee Report (MOPC Presentation – Attachment 9). Mr. Perkins provided an update on MOPC activities. Mr. Richard Ross then presented the Market Working Group (MWG) report (MWG Report – Attachment 10). Mr. Ross reviewed background for the market implementation and presented the following recommendation for Board approval: The MOPC supports the recommendation of the MWG to implement the EIS Market by May 1, 2006. Mr. Skilton moved to approve the May 1 date for market implementation. Ms. Bernard seconded the motion. The Members were unanimous in favor. The motion passed. Mr. Eckelberger stressed the need to make the May 1, 2006 deadline. Mr. Dennis Reed reviewed MOPC recommendations coming from the Regional Tariff Working Group including:


5

1. Mr. Reed provided background for the transmission definition (Transmission Definition Recommendation – Attachment 11). The MOPC approved an amended transmission definition modifying Attachment AI, section II, paragraph 1 at their July 12 – 13 meeting to read: All non-radial power lines, substations, and associated facilities, operated at 60 kV or above, plus all radial lines and associated facilities operated at or above 60 kV that serve two or more eligible customers not Affiliates of each other.

Mr. Harry Dawson presented background and reasons for an amended definition omitting the last phrase:

All non-radial power lines, substations, and associated facilities, operated at 60 kV or above, plus all radial lines and associated facilities operated at or above 60 kV.

Mr. Skilton moved to approve the transmission definition as presented by MOPC with the modifications to Attachment AI, section II, paragraph 1. Mr. Jackson seconded the motion. During considerable discussion a third option was drafted with the following additions:

All existing non-radial power lines, substations, and associated facilities, operated at 60 kV or above, plus all radial lines and associated facilities operated at or above 60 kV that serve two or more eligible customers not Affiliates of each other. All facilities operated at 60kV and above constructed in the future would be included.

Mr. Eckelberger asked for a straw vote from the Members on each of the three drafts. The first draft as presented by MOPC received a vote of 5 for, 7 against, and 2 abstentions. The second draft from OMPA received a vote of 8 for, 4 against, and 2 abstentions. The third draft received a vote of 7 for, 6 against, and 1 abstention. Mr. Skilton and Mr. Jackson withdrew the original motion. Mr. Brown moved to approve draft number three stating that it was a good compromise of the first two drafts. Ms. Bernard seconded the motion. Mr. Eckelberger called for another Members vote on the third draft to see if any opinions had changed during discussion. A second Members vote for the third draft received 8 for and 6 against. The directors voted and the motion passed.

2. Mr. Reed provided background for Tariff modifications to: a) Schedule 1 and Attachment L implementing

the removal of pancaked scheduling fees; b) Attachment L reflecting allocation of money between Transmission Owners in the same zone; and c) continuation of the experimental Transmission Service Prepayment option for an additional year (Tariff Modifications – Attachment 12). Mr. Skilton moved to approve the Tariff modifications as presented. Mr. Altenbaumer seconded the motion. The Members were unanimous in favor. The motion passed

Agenda Item 7 – Compliance Committee Report Mr. Josh Martin presented the Compliance Committee Report (CC Report – Attachment 13). Mr. Martin stated that the committee met June 3. Committee activities included a review of the State of the Market Report filed at FERC; extension of the Boston Pacific’s contract through the end of 2005, which falls within the approved budget; and a NERC compliance update. Regarding NERC compliance, two member companies were cited for violations relating to a lack of NERC-certified operators. One company has resolved this matter and the other company expects to resolve this violation through attrition later this year. NERC has published the results of an SPP Readiness Audit performed in April 2005. Southwest Power Pool did well with positive observations. The next Compliance Committee meeting is September 28 in Chicago. Mr. Craig Roach provided an Independent Market Monitor report (IMM Report – Attachment 14). Mr. Roach stated that the 2004 State of the Market Report was filed May 31, 2005. Two testimonies were filed in support of the SPP EIS Market Tariff revisions on June 15, 2005. There were few protests with an overall constructive tone. The MO-KN-OK Agreement comments are at FERC.


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Agenda Item 8 – Strategic Planning Committee Report Mr. Richard Spring presented the Strategic Planning Committee Report (SPC Report– Attachment 15). Mr. Spring stated that the SPC held a planning retreat May 12-13, which was well attended with representatives from the RSC, FERC, DOE, and SPP independent board members. Another SPC meeting was held on July 14 discussing: fee waiver, Strategic Plan 2005, Entergy ICT, North Carolina LSE, regulatory updates, and organization effectiveness. Mr. Spring explained that two years ago the SPC developed a Strategic Plan, which was expected to take 5 years to implement. Approximately 95% of that plan has been achieved. The Strategic Plan 2005 has been drafted for 1 to 3 years into the future with a long-term plan to follow (Strategic Plan – Attachment 16). The Strategic Plan 2005 addresses: market development, transmission expansion, administrative processes, retention and addition of members, and enhanced regional planning. Mr. Spring made the following recommendation (Strategic Plan Recommendation – Attachment 17):

The Strategic Planning Committee recommends that the SPP Board of Directors adopt the proposed Strategic Plan included in this report, and authorize the delegation of responsibilities to SPP organizational groups also contained herein under the coordination oversight of the SPC and MOPC.

Mr. Skilton moved to approve the Strategic Plan 2005. Mr. Brown seconded the motion. The Members were unanimous in favor. The motion passed. Mr. Spring provided background on the fee waiver process as directed by FERC and presented the following SPC recommendation (Fee Waiver Recommendation – Attachment 18):

Approval of the Bylaws and Membership Agreement amendments as presented to waive those portions of the withdrawal obligation related to long-term commitments and future interest for large retail customer Members, small retail customer Members, and alternative power/public interest Members so long as the entity is not a market participant, effective July 26. Affirmation that the membership of entities with affiliate relationships as defined in the SPP Bylaws will be considered separate for purposes of eligibility for the fee waiver.

Mr. Altenbaumer moved to approve the fee waiver recommendation. Mr. Skilton seconded the motion. The Members were unanimous in favor. The motion passed. Agenda Item 9 – Entergy ICT Proposal Mr. Bruce Rew provided a report on the Entergy ICT Proposal (Entergy ICT Proposal- Attachment 19). In a FERC ICT declaratory order, it was assumed that SPP would be selected as the ICT for Entergy as SPP complies with the independence requirement. The primary functions would be:

• Reliability Coordinator • Tariff Administrator • Calculation of ARCs • Transmission Planning • Weekly Procurement Process

Mr. Rew presented an Entergy ICT Buisness Plan (Entergy ICT Business Plan – Attachment 21) and the following recommendation:


7

Staff recommends that the Entergy ICT Business Plan Proposal be approved in substantially the form presented, and that the officers of SPP be granted the authority to execute the documents necessary to develop this project.

Mr. Brown moved to approve the Entergy ICT Business Plan Proposal as presented. Ms. Bernard seconded the motion. The Members were unanimous in favor. The motion passed. Other Business Mr. Nick Brown reported that the Corporate Governance Committee is required to nominate a replacement for any committee vacancies reporting to the Board. The committee recommends that Larry Altenbaumer replace Bob Schoenberger on the Finance Committee. Mr. Brown moved for Board approval and Mr. Skilton seconded. Mr. Eckelberger asked for any objections. Hearing none, Mr. Larry Altenbaumer will serve as a member of the Finance Committee. Mr. Harry Skilton reported that the system enhancements required to implement the EIS market will necessitate amending SPP’s 2005 capital expenditures budget. SPP’s existing capital budget of $12.8M is insufficient to fully fund the new incremental capital costs associated with the system enhancements. Mr. Skilton moved to increase the approved 2005 capital budget to $18.3M. Mr. Brown seconded the motion. The Members were unanimous in favor. The motion passed. Agenda Item 10 – Future Meetings Mr. Nick Brown called attention to the future meeting schedule for 2006 and 2007 (Future Meetings – Attachment 21). He noted that the June meeting in 2006 would be changed to June 12-13. Also noted, there will be two additional meetings each year: one in June for educational purposes and one in December for administrative or organizational purposes. The meeting locations will remain the same each year. Adjournment With no further business, Mr. Eckelberger thanked everyone for participating and adjourned the meeting at 3:25 p.m. Stacy Duckett, Corporate Secretary

SPP BOARD OF DIRECTORS EXECUTIVE QUARTERLY REPORT

3Q 2005

SUMMARY

3Q 2005 1Q 2005 1Q 2005 4Q 2004 3Q 2004

Tariff Administration Service, Fees & Assessments

$37.8M (YTD) $24.7M $11.7M $40.3M $31.0M

Operating Expenses $33.4M (YTD) $21.1M $11.1M $28.4M $20.8M

Operating Cash Flow $7.7M (YTD) $1.8M $477K $18.7M $3.5M

Cash on Hand $42.8M (09/30/05) $39.0M $40.1M $47.6M $42.1M

TLR Events 115 111 31 105 128

Tags (daily average) 516 456 472 416 440

Transmission Service Requests

57,703 43,979 42,720 61,504 65,099

Transmission Service Study Queue

180 requests/104 studies

195/97 184/95 172/74 136/63

Generation Interconnection Queue

39 requests 33requests

34 requests

35requests

37requests

Stakeholder Meetings 53 41 52 55 55

FERC/State Commissions Dockets Pending

34 21 20 15 13

Legal Matters Pending 3 3 3 0 0

Executive Industry Activities 30 56 38 27 26

Number of Members 45 45 45 43 48

Withdrawal Notices 5 (2005)3 (2006)

7 (2005) 1 (2006)

8 (2005) 8 (2005) 15 (2004)2 (2005)

Staff 157 144 137 131 131


3Q 2005

NOTES TO FINANCIAL STATEMENTS Balance Sheet

• Cash balances increased by $3.7 million from the 2nd quarter. This increase resulted primarily from the positive cash flow from operations of $5.8 million partially offset by $2.1 million in capital expenditures in the 3rd quarter.

• Accounts receivable and accounts payable resulting from tariff activities are now reported on a net basis as a result of accounting rule interpretation. This effectively leaves only SPP’s administrative fee remaining in accounts receivable.

• Overall increase in A/R of $0.7 million is attributable mainly to normal activity within the A/R tariff account

• Other current assets decreased $2.0 million primarily due to the 3rd quarter billing of Schedule 12 revenue that had been accrued for in the 1st and 2nd quarters of 2005.

• Net fixed assets increased $1.3 million as SPP booked nearly $2.1 million in gross purchases during the 3rd quarter. Over $0.8 million of the purchases were related to the imbalance energy market initiative. Remainder of the increase is attributable to software and hardware purchases of $0.7 million and $0.6 million, respectively.

• Total current liabilities increased $1.5 million from the 2nd quarter primarily due to an increase in other current liabilities of $2.2 million partially offset by a decrease in accounts payable of $0.9 million. The increase in other current liabilities is attributable to the 3rd quarter addition to the FERC assessment liability of $1.8 million. Decrease in accounts payable is due to the 3rd quarter payment of several significant consulting invoices that were accrued for at June 30.

• Members’ equity increased by $2.2 million as a result of retention of earnings. Income Statement

• Revenues from tariff administration were favorable to budget by approximately $1.4 million due to the level of services taken under the tariff being greater than what was assumed in the budget.

• Revenues from fees and assessments were below budget by almost $1.0 million primarily due to SPP’s budget assumption of recovering the FERC assessment effective January 2005 when it actually did not commence until March 2005 ($0.6 million/ month).

• Miscellaneous income exceeded budget by nearly $1.7 million primarily due to the 2nd quarter catch up on revenue recognized for impact studies.

• Operating expenses fell $6.6 million short of budget primarily due to project timing/schedule changes, specifically with the shift in market implementation from March 2005 to May 2006. The expenses are still expected to be incurred. The most notable variance is the salary and benefits line item, which results from a greater number of new headcount being assumed in the budget than was actually added 2005 year to date. Additionally, the cash basis budget will cause some variance in comparison to the accrual based financial statements primarily as it relates to leases, maintenance, and insurance costs.


3Q 2005

• Νet other income/expense was favorable to budget by $1.0 million largely due to earnings on deposits being greater than what was assumed in the budget ($0.6 million) and budgeted bad debt expense not being recognized to date (0.3 million).

Cash Flow

• SPP recorded a net decrease in cash of $4.9 million through the 3rd quarter (year to date). This is primarily the result of capital expenditures of $7.5 million and the principal payment made on the 7.5% note of $5.0 million. These outflows were partially offset by the positive cash flow from operations of approximately $7.6 million.

Southwest Power Pool Balance Sheet

As of September 30, 2005

($000) Sep. 30, 2005 June 30, 2005 VarianceASSETS

Current AssetsCash & Equivalents 28,124 24,972 3,152 Restricted Cash Deposits 14,654 14,062 592 Accounts Receivable (net) 4,755 4,056 699 Other Current Assets 2,284 4,286 (2,002)

Total Current Assets 49,817 47,376 2,441 Total Fixed Assets 24,832 23,487 1,345 Total Other Assets 477 497 (20)

TOTAL ASSETS 75,126 71,361 3,766

LIABILITIES & EQUITYLiabilities

Current LiabilitiesAccounts Payable (net) 1,076 1,980 (903) Customer Deposits 14,158 13,926 231 Current Maturities of LT Debt 5,000 5,000 -Other Current Liabilities 6,788 4,590 2,198

Total Current Liabilities 27,022 25,496 1,526 Long Term Liabilities

7.50% Senior Notes - 2008 10,000 10,000 -4.78% Senior Notes - 2011 25,000 25,000 -

Total Long Term Liabilities 35,000 35,000 -Total Liabilities 62,022 60,496 1,526 Total Members' Equity 13,105 10,865 2,239

TOTAL LIABILITIES & EQUITY 75,126 71,361 3,766

Southwest Power PoolStatement of Income and Members' Equity

For the Nine Months Ended September 30, 2005

($000)Actual

Jan - Sep 05Budget

Jan - Sep 05Variance to Budget

Actual Jan - Sep 05

Actual Jan - Sep 04 Variance

Ordinary Income/ExpenseIncome

Tariff Administration Service 31,725 30,293 1,432 31,725 29,225 2,500 Fees & Assessments 6,072 7,032 (959) 6,072 1,807 4,265 Contract Services Revenue 37 - 37 37 - 37 Miscellaneous Income 2,464 720 1,744 2,464 1,253 1,211

Total Income 40,298 38,045 2,253 40,298 32,285 8,013

ExpenseSalary & Benefits 12,445 14,265 (1,820) 12,445 10,621 1,824 Employee Travel 484 549 (65) 484 411 73 Administrative 1,467 1,546 (79) 1,467 812 656 Assessments & Fees 5,931 5,932 (0) 5,931 503 5,429 Meetings 264 307 (44) 264 233 30 Communications 1,306 2,460 (1,154) 1,306 878 429 Leases & Maintenance 1,587 3,168 (1,581) 1,587 2,282 (695) Services 6,877 6,673 204 6,877 5,106 1,771 Regional State Committee 956 1,370 (413) 956 2 955 Depreciation & Amortization 2,059 3,661 (1,602) 2,059 3,332 (1,273)

Total Expense 33,377 39,931 (6,554) 33,377 24,179 9,198

Net Ordinary Income 6,920 (1,886) 8,807 6,920 8,105 (1,185)

Other Income/ExpenseOther Income

Asset - - - - 2 (2) Withdrawal Obligation Income - - - - 641 (641) Interest Income 645 90 555 645 137 508

Total Other Income 645 90 555 645 780 (135)

Other ExpenseInterest Expense 1,756 1,969 (213) 1,756 1,573 183 Bad Debt Expense - 250 (250) - 53 (53)

Total Other Expense 1,756 2,219 (463) 1,756 1,626 130

Net Other Income (Expense) (1,111) (2,129) 1,018 (1,111) (846) (265)

Net Income 5,810 (4,015) 9,824 5,810 7,259 (1,449)

Southwest Power Pool Statement of Cash Flows


($000) Jan - Sep 05OPERATING ACTIVITIES

Net income 5,810 Adjustments to reconcile net income (loss)to net cash provided by operations:

Depreciation 1,998 Amortization 61 Changes in assets and liabilities: Accounts receivable (561) Accrued revenue (793) Prepaid expenses (1,203) Accounts payable (581) Other current liabilities 5,204 Customer deposits (2,272)

Net cash provided by operating activities 7,664

INVESTING ACTIVITIESPurchase of property and equipment (7,536)

Net cash used by investing activities (7,536)

FINANCING ACTIVITIESRepayment on 7.5% Senior Notes - 2008 (5,000)

Net cash used by financing activities (5,000)

Net cash decrease for period (4,873)

Cash at beginning of period 47,651 Cash at end of period 42,778

Southwest Power Pool Capital Expenditures


($000)Jan - Sep 05 Budget Variance to Budget 2005 Budget

Imbalance Market 4,054 5,092 (1,038) 10,722 Primary Operations Center 344 2,667 (2,323) 3,650 Maintenance - Software 1,597 1,677 (80) 1,716 Maintenance - Hardware 1,541 2,195 (653) 2,213 Total Capital Expenditures 7,536 11,631 (4,094) 18,300


3Q 2005

RELIABILITY COORDINATION TLR Events per Quarter

0

20

40

60

80

100

120

140

# of

Eve

nts

SPP 115 111 31 105 128

3Q-05 2Q-05 1Q-05 4Q-04 3Q-04

3Q05 v. 3Q04 shows a slight decrease.

MW Curtailed due to TLR

0

20000

40000

60000

80000

100000

120000

140000

160000

180000

3Q-05 2Q-05 1Q-05 4Q-04 3Q-04

MW Firm

Non-Firm

3Q05 v. 3Q04 shows a slight decrease in MW curtailed due to TLR.


3Q 2005

SCHEDULING

Daily Average Tags Processed

0

100

200

300

400

500

600

Num

ber o

f Tag

s

SPP 516 456 473 416 440

3Q-05 2Q-05 1Q-05 4Q-04 3Q-04

3Q05 v. 3Q04 shows increase in the number of tags processed.

TARIFF ADMINISTRATION

Total Requests Submitted

0

10000

20000

30000

40000

50000

60000

70000

SPP 57703 43979 42720 61504 65099

3Q-05 2Q-05 1Q-05 4Q-04 3Q-04

3Q05 v. 3Q04 shows decrease in total transmission service requests.


3Q 2005

% of Total Requests that are Confirmed

0%

10%

20%

30%

40%

50%

60%

SPP 48% 36% 56% 32% 29%

3Q-05 2Q-05 1Q-05 4Q-04 3Q-04

3Q05 v. 3Q04 shows strong increase in percentage of transmission service requests confirmed.


3Q 2005

QUEUE STATUS REPORT Transmission Service Request Queue

Number of requests/studies = 180/104, representing 15,249 MW Number of non-DC Tie requests/studies = 87/71, representing 6,239 MW There are 82 requests/26 studies for DC Tie requests representing 8,456 MW that cannot be processed due to impending DC Tie competition. During the same period last year, there were 136 requests/63 studies in process, representing 18,090 MW. There were 76 requests/24 studies for DC Tie requests representing 8,072 MW that could not be processed due to impending DC Tie competition. Generation Interconnection Queue

Number of requests = 39, representing 7,260 MW • Number of wind requests = 27, representing 4,833 MW • Number of fossil fuel requests = 12, representing 2,427 MW Number of requests with Interconnection Agreement pending = 10 Interconnection Agreements signed during 2005 = 3 During the same period last year, there are 37 requests in process (26 wind; 11 fossil fuel) representing 9,078 MW (4,279MW wind; 4,799 MW fossil fuel). There were 9 Interconnection Agreements pending.


3Q 2005

SPP DOCKETS AT FERC/STATE COMMISSIONS

DOCKET

NUMBER CASE NAME DESCRIPTION CURRENT STATUS

RT04-01and ER04-48

Southwest Power Pool, Inc.

SPP filed a proposal for recognition as an RTO. By order issued February 10, the Commission accepted SPP’s proposal for recognition as an RTO subject to conditions and compliance filing requirements. On October 1, 2004 FERC issued an Order on SPP’s August 2, 2004 compliance filing. The order recognized SPP as an RTO and required several additional compliance steps by November 1. FERC then issued a February 11, 2005 Order addressing SPP’s compliance filings and directing SPP to make additional filings. SPP filed a proposal for revisions to SPP’s Bylaws and Membership Agreement to provide for independence of SPP’s compliance function, clarify a SPP Member’s Withdrawal/ Termination Obligations, and, in compliance with the Commission’s February 11 Order, provide for a Fee Waiver.

On August 9, 2005 SPP submitted a filing providing for revisions to its Bylaws and Membership Agreement. On August 26, 2005, SPP submitted its compliance filing and progress report, addressing Grandfathered Agreement conversion issues, pursuant to FERC’s October 2, 2004 order in this proceeding and in fulfillment of SPP’s August 2, 2004 commitment. On September 20, 2005 FERC issued an order which: granted in part and denied in part the rehearing requests; conditionally accepted SPP compliance filing; and directed SPP to submit a compliance filing within 30 days.

RM05-5-000

Standards For Business Practices And Communications Protocols For Public Utilities

The FERC issued a NOPR with regard to a proposal to include in its regulations by reference certain Standards for Business Practices and Communication Protocols for Public Utilities. These standards would be those promulgated by the North American Energy Standards Board’s (“NAESB”) Wholesale Electric Quadrant (“WEQ”).

On July 1, 2005, SPP joined comments filed by the ISO/RTO Council encouraging FERC to accept some standards while allowing review of others.


3Q 2005

DOCKET


ER05-666 Southwest Power Pool, Inc.

SPP filed certain Tariff modifications providing for Generation Imbalance Service (Schedule 4-A), Limitation of Liability, refinement of monthly demand charge and zone transmission load, modification of Schedule 9 to allow a Transmission Owner to avoid paying itself for Network Service, redispatch for Short-Term Firm Transmission Service, and modifications to reflect correct Zone name references and clerical errors.

On July 21, 2005, the FERC issued an order in this docket. In the Order, all provisions of the filing were accepted with two exceptions. On August 22, 2005, SPP submitted its compliance filing, providing revisions to its OATT pursuant to the Commissioner’s Order issued 7/21/05. FERC issued an Order Granting Rehearing for Further Consideration on September 21, 2005.

ER05-1285 Southwest Power Pool, Inc

On August 2, 2005, SPP filed at the FERC three sets of revisions to its OATT: (1) to modify the definition of Transmission Facilities by adding a new Attachment AI and revising the Definitions section; (2) to revise Attachment L to provide for the distribution of revenue between multiple entities owning transmission facilities in a single zone (sometimes referred to as compensation for customer-owned transmission facilities); and (3) to revise Schedule 1 (Scheduling, System Control and Dispatch Service) to eliminate assessment of multiple scheduling charges for a single reservation or transaction and to revise Attachment L (Treatment of Revenues) to provide for the allocation of scheduling revenue under the new rate design

On September 30, 2005, the FERC accepted the proposed revisions to the Schedule 1 and Attachment L. The FERC also accepted the proposed revisions to the Definitions section and the new Attachment AI, but only after SPP made modifications to the definitions and Attachment AI to comply with the order.


3Q 2005

DOCKET



On February 11, 2005, SPP submitted an Agreement for Wholesale Distribution Services Charges between Kansas Electric Power Cooperative, Inc and the Empire District Electric Co.

On May 12, 2005, SPP submitted a compliance filing consistent with a 4/13/05 unpublished letter order, providing SPP’s corrected designation to the Agreement for Wholesale Distribution Service Charges between Electric Power Cooperative, Inc and the Empire District Electric Company and a refund report. FERC accepted SPP’s submittal on August 19, 2005.

ER05-1051 and ER05-

1052

Westar Energy, Inc.

On May 31, 2005, Westar and SPP separately filed an unexecuted service agreement to provide KPP with ancillary services. Under the Agreement, KPP may self-supply all or a portion of its ancillary services as allowed in the SPP OATT. SPP filed to remove the reference to the transmission owner from Section 3.0 of the KPP Ancillary Services Agreement and there is to be a Settlement Conference regarding the unexecuted ancillary services agreement between SPP and KPP

On September 7, 2005, an order was issued scheduling a settlement conference for Friday, October 7, 2005.


In a May 2 Filing, Westar proposed to (a) update Westar's rates to recover the costs of providing transmission and ancillary service; and (b) adopt a formula rate approach to determining and keeping the transmission service rates current. SPP submitted this filing to merely track the proposed rates for transmission service applicable to the Westar pricing zone.

The effective date for Westar’s filing has been delayed for five months subject to hearing and settlement proceedings. No other FERC action has been taken on this docket.


3Q 2005

DOCKET



On February 8, 2005, SPP filed a revision to its open access transmission tariff to add Schedule 12 in order to recover SPP's payments to FERC's Annual Charges.

Interventions and Protests have been filed and SPP filed an answer to the protests on April 4, 2005. On April 8, 2005 FERC accepted the filing and suspended it, subject to the outcome of Settlement and Hearing Proceedings. After initiating settlement proceedings, FERC issued an order on clarification on June 3, 2005 and accepted the tariff revisions as filed.


SPP filed Attachment AD on November 1, 2004 to provide an interim agreement between SPP and Southwestern Power Administration until a permanent agreement can be executed.

On February 8, 2005, SPP filed a supplement to Attachment AD and a revised agreement. On March 31, 2005, FERC accepted Attachment AD and the revised agreement. The SPA coordination agreement was filed on May 16, 2005. FERC accepted the agreement by letter order on June 30, 2005.

ER04-1232 Southwest Power Pool, Inc. SPP filed an amendment to the SPP OATT to implement a rate change proposed by Excel for Southwestern Public Service in Docket ER04-1174-000.

FERC accepted the revisions, suspended them for five months, to become effective June 1, 2005, subject to refund, and established hearing and settlement judge procedures. On February 14, 2005, FERC granted rehearing to allow additional time to consider the issues.


3Q 2005

DOCKET


ER99-4392 East Texas Electric Cooperatives, Inc. v. FERC

SPP filed revisions to its tariff in order to implement network integration transmission service. FERC granted a rehearing request in accordance with a Court decision to remand the case to FERC. At OG & E’s request, FERC decided the major issue in the case was whether redispatch is required to sustain non-firm service, and FERC found that it was not.

On February 11, 2005, FERC accepted SPP’s past compliance filing and directed SPP to make a new compliance filing. SPP filed on March 14, 2005. On June 3, 2005 FERC issued an order on clarification that affirmed its position and accepted SPP’s tariff filing.


On June 15, 2005, SPP submitted proposed revisions to its Open Access Transmission Tariff to incorporate Energy Imbalance Market and Market Monitoring Plan, effective 3/1/06. On September 6, 2005, SPP filed an answer to comments and protests of SPP’s filing of tariff revisions to implement an energy imbalance market.

On September 19, 2005 FERC issued an order on proposed tariff revisions rejecting SPP’s filing and providing guidance on the following issues: (1) reliable and stable market operations; (2) market-based rates; and (3) mitigation and monitoring provisions. SPP needs to submit revised, comprehensive energy imbalance and market monitoring and mitigation plans.


3Q 2005

DOCKET


ER04-1232 Southwest Power Pool, Inc. Filing of an amendment to the SPP OATT to implement a rate change proposed by Excel for Southwestern Public Service in Docket ER04-1174-000

FERC accepted the revisions, suspended them for five months, to become effective June 1, 2005, subject to refund, and established hearing and settlement judge procedures. On February 14, 2005, FERC granted rehearing to allow additional time to consider the issues.


On February 28, 2005, SPP submitted a filing to revise its Tariff to implement a regional transmission cost allocation proposal with regard to new transmission upgrades. This proposal was developed by the Regional State Committee.

FERC accepted SPP’s filing of the proposal to become effective on May 5, 2005. SPP then made a compliance filing on May 23, 2005 providing for revisions to its Tariff. FERC then granted rehearing on June 22, 2005. No final decision has been made in this docket.

ER99-4392 East Texas Electric Cooperatives, Inc. v. FERC

SPP filed revisions to its tariff in order to implement network integration transmission service. FERC granted a rehearing request in accordance with a Court decision to remand the case to FERC. At OG & E’s request, FERC decided the major issue in the case was whether redispatch is required to sustain non-firm service, and FERC found that it was not.

On February 11, 2005, FERC accepted SPP’s past compliance filing and directed SPP to make a new compliance filing. SPP filed on March 14, 2005. On June 3, 2005 FERC issued an order on clarification that affirmed its position and accepted SPP’s tariff filing.


SPP made revisions to its Tariff in order to incorporate Aquila Networks-L&P ("L&P'), Aquila Networks-MPS ("MPS"), and Aquila Networks-WPK ("WPK") as Transmission Owners participating in the SPP Tariff.

FERC accepted the filing on June 30, 2005.


3Q 2005

DOCKET



SPP filed an unexecuted Network Integration Transmission Service Agreement between SPP-OG&E-OMPA to rollover grandfathered transmission from the OG&E tariff to the SPP Tariff

On August 23, 2005 a FERC settlement judge issued a report recommending continuance of the current settlement procedures.

ER05-1012; ER05-1072

Union Electric Co. d/b/a Ameren UE

American Electric Power Co.

Ameren UE & AEP-PSO each submitted a notice of cancellation of an amended interchange agreement known as the Mo-Kan-Ok agreement.

On September 2, 2005 Associated Electric Cooperative, Inc submitted its answer to Xcel Energy Services, Inc.’s August 22, 2005 request for clarification of the Commission’s July 22, 2005 order in this proceeding. AEC contends that the Commission should reject the Request for Clarification and affirm the July 22, 2005 Order under which the Commission accepted the notices of cancellation of the Mo-Kan-Ok Agreement.. No FERC action has been taken in this docket.

ER04-699-000; ER05-

1065 Entergy Services, Inc.

Federal Energy Regulatory Commission proceedings concerning Entergy’s ICT proposal.

Entergy filed its enhanced ICT proposal on January 3, 2005. On March 11, 2005 FERC conditionally accepted Entergy’s filing. SPP intervened on June 7, 2005 and has filed testimony in this docket. No FERC decision has been made.


3Q 2005

DOCKET


ER05-925; ER05-990

Westar Energy, Inc.

FERC issued an Order accepting SPP’s May 19, 2005 filing for revision of the rates for the Westar Zone and suspending it for five months, to become effective December 1, 2005, subject to refund and subject to the outcome of Dockets. December 1, 2005 is the effective date for Westar’s rate increase, subject to refund and subject to the outcome of Docket No. ER05-925-000.

On August 19, 2005 FERC issued an order of the Chief Judge adopting a protective order, pursuant to Westar’s August 15, 2005 motion for adoption of a protective order. On August 29, 2005, FERC issued an order of the Chief Judge continuing settlement judge procedures.

ER05-1151-000; ER05-

226-001

Southwest Power Pool, Inc. On June 27, 2005, SPP filed of a revision to the PSO-GRDA interconnection agreement, effective dates of December 1, 2004 and May 26, 2005.

On August 5, 2005 FERC accepted for filing, effective 12/01/04 and 5/26/05, SPP’s Revised Interchange and Interconnection Agreement designated as Service Agreement 1135.


SPP filed to provide a 10 month report on the results of Attachment AA in compliance with the Commission’s October 5, 2004 Order in ER04-833 and requested an extension of the program another year

FERC issued a Notice of Filings # 1 acknowledging the 8/05/05 filing of SPP’s status but has not issued a decision in this docket..

ER04-434-004 Southwest Power Pool, Inc. SPP filed revised tariff sheets in compliance with Order 2003-C.

On August 15, 2005 ,SPP filed revised tariff sheets to SPP's OATT incorporating the changes to the pro forma LGIP and LGIA identified in Appendix A to Order No. 2003-C. On September 30, 2005 FERC issued a Letter Order accepting SPP’s filing, to become effective July 18, 2005, as requested.


3Q 2005

DOCKET


ER05-989-001 Kansas City Power & Light Co and the City of Garnett, Kansas

SPP filing of Amendatory Agreement No. 4 to the Municipal Participation Agreement between KCPL and Garnett, KS

On September 12, 2005, in compliance with FERC’s July 13, 2005 order, SPP filed Amendatory Agreement No. 4 to the Municipal Participation Agreement between Kansas City Power & Light Company and the City of Gamett, Kansas.

ER05-651-003 Southwest Power Pool, Inc. SPP filing in compliance with FERC’s August 25, 2005 Order on the SPP, PSO, FPL Cowboy interconnection agreement.

On September 27, 2005, SPP submitted a revised version of the Large Generator Interconnection Agreement between SPP, FPL Energy Cowboy Wind, LLC, and Public Service Company of Oklahoma. On October 3, 2005 FERC acknowledged this filing via its Combined Notice of Filings # 1.

ER03-765-001 Calpine Oneta Power, L.P.

Calpine initiated this proceeding by filing its proposed rate schedule on April 22, 2003, seeking to collect from SPP its alleged reactive power revenue requirement of $2,455,169.96 totaling over $5.5 million dollars to date and growing, relating to the alleged provision of reactive power services from the Calpine Oneta facility.

On September 16, 2005, SPP filed its Reply Brief in response to the Initial Brief of Calpine pursuant to Rule 706 of FERC’s Rules of Practice and Procedure and the December 22, 2004 Order Setting Procedural Schedule. An initial decision is scheduled by November 3, 2005.

ER05-1300 Southwest Power Pool, Inc On August 5, 2005, SPP filed a status report on the implementation of Attachment AA of the SPP OATT.

On September 20, 2005, the FERC accepted SPP’s filing and extended Attachment AA for one year.


3Q 2005

DOCKET


RM04-12

Financial Reporting and Cost Recovery Practices for Regional Transmission Organizations and Independent System Operators

Comments due NOPR on Accounting and Financial Reporting for Public Utilities Including RTOs

Many entities filed comments in response to FERC’s June 2, 2005 notice of proposed rulemaking.


3Q 2005

DOCKET


ER05-652 Southwest Power Pool, Inc. FERC's Order on Rehearing and Compliance Filing on SPP's Cost Allocation Proposal

On September 20, 2005 FERC issued an Order on Rehearing and Compliance Filing addressing rehearing requests of its April 22, 2005 order on SPP's proposal for a regional transmission cost allocation plan and accepting SPP's May 5, 2005 compliance filing, subject to further compliance filings. FERC denied rehearing of most issues, but granted rehearing of a limited number of issues. FERC ordered SPP to remove the fuel diversity provision from the non-exhaustive list of waiver criteria, upheld the decision that Attachment Z does not contain provisions for impermissible "and" pricing, and granted certain clarifications with respect to Attachment Z. A compliance filing is required by October 20, 2005. SPP is permitted to file a tariff provision clarifying that the right of first refusal provision is a cost allocation mechanism, not an ownership mechanism.


3Q 2005

DOCKET


Arkansas 04-137-U

Southwest Power Pool, Inc. SPP’s CCN Filing with APSC for recognition as a public utility.

On October 13, 2004, SPP made a CCN Filing with APSC for recognition as a public utility and asked for disclaimer of regulation. SPP filed testimony and the Cost/Benefit Study on June 17, 2005. The APSC has submitted numerous data requests and SPP complying with the requests. On September 29, 2005, the APSC issued an order granting Staff's motion to consolidate the applications of the SPP Transmission Owners with SPP's docket.

Louisiana U-28155

Entergy Services, Inc. Louisiana Public Service Commission proceedings concerning Entergy’s ICT proposal

SPP filed an intervention on September 13, 2004. Entergy filed its enhanced ICT proposal on January 6, 2005. SPP has filed both direct testimony and cross-answering testimony regarding SPP’s capability to perform the ICT function. A hearing is set for October 17, 2005.

Arkansas 04-050-U

Entergy Services, Inc.

An Investigation regarding Entergy Arkansas, Inc.’s participation in an Entergy-only independent transmission system administrator structure as compared to its participation in the Southwest Power Pool Regional Transmission Organization.

SPP has filed initial and reply comments in the proceeding.


3Q 2005

DOCKET


Missouri EO-2006-0141

and EO-2006-0142

In the Matter of the Applications of the Empire District Electric Company and Kansas City Power & Light Company for Authority to Transfer Functional Control of Certain Transmission Assets to SPP

Applications with the Missouri Public Service Commission requesting approval to transfer the functional control of certain transmission assets to the SPP, to continue participation in the SPP RTO, and to take network integration transmission service from SPP to serve each company’s retail load in Missouri.

On September 28, 2005 the Empire District Electric Company and the Kansas City Power & Light Company each filed an application with the Missouri Public Service Commission requesting approval to transfer the functional control of certain transmission assets to the SPP, to continue participation in the SPP RTO, and to take network integration transmission service from SPP to serve each company’s retail load in Missouri. On September 30, 2005 SPP filed an Application to Intervene in the above-referenced matters, submitting in support of its application the SPP RSC Cost-Benefit Analysis and the testimony of Les Dillahunty; Ralph L. Luciani and Ellen Wolfe; and Richard A. Wodyka.

Kansas 06-SPPE-202-

COC Southwest Power Pool, Inc.

An application of SPP for a Certificate of Convenience and Authority for the limited purpose of managing and coordinating the use of certain transmission facilities located within Kansas.

On August 31, 2005 SPP applied for a Certificate of Convenience and Authority for the limited purpose of managing and coordinating the use of certain transmission facilities within Kansas. No decision has been issued in this docket.


3Q 2005

LEGAL MATTERS PENDING

Party/Description Issue

Reliant Energy Disputed withdrawal fee.

City of Jonesboro Demand letter sent for repayment of membership overpayment.

EEOC Charge Former SPP employee filed EEOC charge. Charge was dismissed.

Mirant Corporation Bankruptcy SPP CFO deposed.


3Q 2005

EXECUTIVE INDUSTRY ACTIVITIES

Executive Event

Nick Brown Oklahoma Bill Signing (July 6) Utilities State Government Organization, Palms, SC (July 11) Kansas Electric Coop Annual Meeting (August 1) Electric Power Research Institute Board Meeting, California (Aug. 6-10) Electric Power Supply Association Executive Conference, Washington,

DC (Aug. 30)

Les Dillahunty National Society of Professional Engineers, Chicago (July 7-9) Member Meeting: American Electric Power (July 20) Entergy ICT Deposition for Louisiana Public Service Commision, New

Orleans (Aug. 24) Missouri Public Service Commission Informational Proceeding

(KCPL/EDE/SPP), Jefferson City (Aug. 30) Member Meeting: Golden Spread (Sep.1) Member Meeting: Golden Spread, Empire, Sunflower (Sep. 2) Oklahoma Emerging Energy Technology Conference, Norman (Sep. 27)

Tom Dunn Missouri Municipal Utility Meeting (Marshall, Slater, Salisbury, Carrolton, Higginsville, KCPL, MJMEUC) (Sep. 1)

Member Meeting: Westar, Wichita (Sep. 26)

Stacy Duckett West Africa Power Pool, SPP Office (Aug. 8) ISO/RTO Council General Council Group, California (Sep. 26-27)

Carl Monroe SPP-MISO Seams Agreement Coordinating Committee (July 19) West Africa Power Pool, SPP Office (Aug. 8) Member Meeting: Golden Spread (Sep. 1) Conference Call with FERC on Long-Term Transmission Rights (Sep. 2) NERC Operating Committee, Dallas (Sep. 14-15) Member Meeting: Westar Visit (Sep. 26)

Charles Yeung ISO/RTO Council, Alberta (July 11) NERC FMWG, Chicago (July 13) RMC, San Diego (Aug. 1) NERC BOT, San Diego (Aug. 1) NERC FMWG (Aug. 30) ISO/RTO Council RLC (Sep. 9) RMC, Dallas (Sep. 14) NERC Regional Delegation Task Group Conference Call (Sep. 27)


3Q 2005

WITHDRAWAL LETTERS MEMBERS EFFECTIVE DATES Cleco Corporation 10/31/06 Grand River Dam Authority 10/31/05 Louisiana Energy & Power Authority 10/31/06 City of Lafayette Utilities System 10/31/06 Midwest Energy 10/31/05 Oklahoma Municipal Power 10/31/05 The Empire District Electric Company 10/31/05 Westar Energy 10/31/05


3Q 2005

STAFFING REPORT

SPP Employee count as of January 1, 2005:

131

1Q New hires: 2Q New hires: 3Q New hires:

8 11 16

YTD Terminations:

1 – Retiree 6 – Voluntary termination 1 – Involuntary termination 1 – Interns (part time/seasonal)

9

SPP Employee count as of September 30, 2005:

157

SPP Employee count as of June 30, 2005:

144

There are 206 full time employees and 2 part time employees in the 2005 budget. (These numbers include positions added mid-year.)

Southwest Power Pool, Inc. COMPLIANCE COMMITTEE

Report to the Board of Directors/Members Committee October 25, 2005

APPEAL PROCESS

Organizational Roster The following members represent the Compliance Committee:

Josh Martin, Chair Phyllis Bernard Quentin Jackson Stacy Duckett

Director Director Director SPP Staff Secretary

Background The Compliance Committee is charged with hearing appeals from members related to findings by the Compliance Department of SPP. Until recently, no such appeal to the Compliance Committee had ever occurred, and therefore no process had been developed. Analysis The Compliance Committee developed and used the attached process for hearing an appeal recently brought to it. The process worked well for all involved. As such, the Committee has adopted this process going forward. It also suggests that this would be a suitable process for all appeals heard by an organizational group of SPP. Recommendation The Compliance Committee recommends approval of this process for appeals heard by the Committee. The Committee also recommends that the Board direct the Markets and Operations Policy Committee and its working groups to implement an appeals process, which may be the same. Action Requested Approval

Approval: Corporate Governance Committee September 28, 2005

Approved by the Compliance Committee September 28, 2005

PROCESS FOR APPEAL OF COMPLIANCE ISSUES TO THE COMPLIANCE COMMITTEE 1

October 2005 SPP Member organizations may appeal a finding of non-compliance by the SPP Compliance Department. As outlined in the Compliance Program, an appeal should first be made to the SPP Organizational Group responsible for the Criteria at issue. Any further appeal(s) may be made to the Markets and Operations Policy Committee (MOPC) and/or to the Compliance Committee (CC). When making an appeal to the Compliance Committee, the following procedure will be applicable.

1) The Appellant must notify, in writing, the Director of Compliance and/or the Staff Secretary to the CC of its request for a review by the CC.

2) The Staff Secretary will notify the CC of the request and develop a timeline for hearing the appeal.

3) The Appellant and the Director of Compliance will submit written statements of their respective positions, as well as any supporting documentation. This must include the findings of previous review(s) by other Organizational Groups.

4) The Staff Secretary will seek other information/documentation as requested by the representatives from the CC.

5) A session will be scheduled (live or teleconference) at which the parties will present their respective positions; the representatives from the CC will seek additional information/clarification from the participants as needed.

6) The CC will reconvene to deliberate within three (3) business days of the session. 7) The CC will issue a Determination to the participants, in writing, within thirty (30) days of the

session. This Determination will be presented at the next regular Board of Directors/Members Committee meeting.

Participants in the appeal session will include:

• The members of the Compliance Committee • The Staff Secretary • A representative for the Appellant(s) • SPP Director of Compliance • A representative from each SPP Organizational Group that has heard an appeal on the issue

Other interested parties may be allowed to participate solely at the discretion of the Chairman of the CC. If the appeal is generally a policy interpretation that impacts multiple parties, the Chairman may conduct it in an open session available to all interested parties. If the appeal involves proprietary and/or competitive information, it will be conducted in a closed session. Participants will be notified in advance whether the session will be open or closed.

1 Once approved, this process will be integrated into the Compliance Program documentation related to appeals.

Southwest Power Pool, Inc.

COMPLIANCE COMMITTEE

September 20, 2005

Determination of Appeal

Participating Parties

Josh Martin, Chair Phyllis Bernard Quentin Jackson Bob Cochran Mike Gammon Heidt Melson Ron Ciesiel

Director Director Director Representing Appellants Operating Reliability Working Group System Protection and Control Working Group SPP Director of Compliance

Background

On August 15, the SPP Compliance Committee heard an appeal of a finding of non-compliance. The appealing parties (six members) were represented by Mr. Bob Cochran from Southwestern Public Service (SPS); the SPP Compliance Department was represented by Mr. Ron Ciesiel, Director of Compliance.

The appeal regarded the results of an Under Frequency Load Shedding Survey conducted to test compliance with SPP Criteria 7.3. The appealing parties were found to be out of compliance, necessitating notification to NERC. NERC policy requires the public posting on its website of the names of entities violating criteria.

The appeal to the Compliance Committee follows appeals to the System Protection and Control Working Group (SPCWG) and the Operating Reliability Working Group (ORWG). These SPP organizational groups are responsible for SPP Criteria. The positions of the appealing parties and the Compliance Department are detailed in written statements provided in advance of the teleconference (attached).

Mr. Joshua Martin, Chairman of the Compliance Committee requested each side provide oral statements summarizing their written statements. Committee members (Martin, Ms. Phyllis Bernard and Mr. Quentin Jackson) sought additional information from the representatives. They also directed questions to Mr. Mike Gammon (representing the ORWG) and Mr. Heidt Melson (representing the SPCWG). The Committee later reconvened to deliberate.

Analysis

The parties themselves do not dispute that they were in violation of the criteria. Results from past audits indicate that these were not isolated, intermittent incidents of non-compliance; but rather, that for the four annual compliance surveys performed by SPP from 2001 to 2004, three of the

companies have been out of compliance for all periods; two of the companies have been out of compliance for three of the periods; and one company has been out of compliance for two of the periods. The request of the parties was for leniency in the imposition of sanctions due to (a) on-going efforts to refine criteria on this issue, and (b) concern about unidentified consequences stemming from NERC's public posting of the non-compliance.

Determination

The issue for the Compliance Committee was whether SPP’s Compliance Department erred in finding the members out of compliance with SPP Criteria. Upon consideration of the facts presented, the Compliance Committee determines that the Compliance Department did not err in finding the members out of compliance with SPP Criteria 7.3. The Criteria require that an entity meet the load shedding requirements at each stage, not just in total. The members cited clearly did not do this.

The committee members are sensitive to the fact that a finding of non-compliance results in a report to NERC and public posting of the violation. However, the ability to reliably operate the transmission grid is paramount; the risks associated with unreliable operation are too great to overlook. The next step in the process has been laid out by NERC: SPP must report the incidents of non-compliance to NERC to be posted on the NERC web site. NERC's actions at this point are not within SPP's authority to control, nor is SPP afforded flexibility in its obligation.

Additional Remarks

The criteria are developed through a detailed, intensive collaborative process between technical experts among the membership in consultation with and reference to national standards for reliability. The ORWG and SPCWG are currently considering revisions to the Criteria relevant to this appeal. While the ultimate outcome of that process is not known, the Compliance Committee encourages these organizational groups to continue their work and bring it to conclusion expeditiously and will recommend that the Board of Directors monitor the progress closely.

Transmission Operations 7/21/05 6086 West 48th Street Amarillo, Texas 79109

SPP Compliance Committee C/O Ron Ciesiel, Compliance Director Southwest Power Pool 415 N. McKinley, 800 Plaza West Little Rock, AR 72205-3020 Gentlemen, Southwestern Public Service Company dba Xcel Energy (SPS) believes that the pending finding that SPS is in violation of the Southwest Power Pool (SPP) Compliance Program Planning Measurement IIIDM2; Under Frequency Load Shedding Program (UFLS) for 2004 should be reversed. We believe that we met the intent of the SPP Criteria, that we have been caught by an unintended consequence of the Criteria’s construction and don’t deserve the public embarrassment that a confirmed violation will produce. We contend that it was not the intent of the Criteria’s framers to penalize a member for compliance survey results such as SPS and other members had. It sometimes happens that rules and criteria are written without the full implications of the rule being realized by the writers. When the full impacts of the written rule become apparent, the writers then undertake to fix the rule. Included with this appeal document is a letter from Southwestern Power Administration (SPA) dated November 19, 2004. In that letter SPA makes good arguments as to the Criteria’s intent versus its application to compliance. It was SPA’s initial appeal of their compliance violation finding and their arguments that sparked the current effort to revise the SPP UFLS Criteria. We offer the ongoing effort by SPP’s committees to revise the SPP Criteria for UFLS as evidence of the Criteria’s intent and SPP’s membership’s desire to fix the Criteria. While the final form of that revision has yet to be set, both the Operating Reliability Working Group (ORWG) and the System Protection and Control Working Group (SPCWG) have approved the essential concept. That essential concept recognizes the difficulty of building a control system that can shed 10% of a member’s load at any and every possible time. Engineering design is a constrained compromise between conflicting factors. The Criteria change effort underway recognizes the engineering compromises between achieving a load shed to arrest a frequency decline, the cost to build the control scheme, and the end power users’ load behavior which varies by time of day and by season.

Page 1

Transmission Operations 7/21/05 6086 West 48th Street Amarillo, Texas 79109

Both the ORWG and SPCWG have agreed in principle to a Criteria that allows a member to shed less than 10% of their load at the second or third under frequency step as long as the cumulative load shed is at least 20% at the second step and at least 30% at the third step. SPS and other members with pending compliance violations of this Criterion would have been found compliant if this change had been made prior to the August 26, 2004 UFLS compliance survey. Their surveys’ results are provided with these members’ consent and is shown in the table below: SPP Member Name

First step percent load shed

Second step percent load shed

Third step percent load shed

Total percentage of load shed

Southwestern Public Service Company

12.99% 8.68% 9.60% 31.27%

City of Independence

11.39% 11.24% 8.0% 30.63%

Southwestern Power Administration

14.95% 8.40% 9.02% 32.38%

City of Lafayette

13.65% 9.97% 7.94% 31.55%

We respectfully request in light of this information and the ongoing effort to change the SPP UFLS Criteria that the pending compliance violation for SPS and the other similarly situated members be set aside. If you are unwilling to take that step until the proposed Criteria change is final and approved, we respectfully request that you direct the compliance violation continue to be held as pending until the Criteria change has been either approved or disapproved. Then at that time we respectfully request that you direct that the revised Criteria be used to measure our compliance for 2004. We believe that the final state of the proposed Criteria change will be determined no later than late 2005. Thank you for your time in reviewing our appeal and considering our request. Sincerely, Bob Cochran Manager, Transmission Control Center

Page 2

Response to member appeal of 2004 UFLS findings

Documentation defending the findings of non-compliance for the six [6] SPP members involved in this appeal

Historical background The SPP Criteria requiring an under frequency load shedding [UFLS] program has been in existence for more than two decades. The foundation for the requirement came from the 1965 New York blackout. All ten [10] NERC Regions developed a similar program with minor local variations but all have the basics of load shedding at a system frequency of ~59.3hz and completing the load shedding at a frequency of ~58.7hz. SPP’s program has consisted of three steps of load shedding at 59.3hz, 59.0hz and 58.7hz with each step shedding 10% for a total load shedding of 30%. SPP Criteria 7.3 [see attached] was evaluated and updated in 2001 when the NERC/SPP Compliance Program introduced compliance monitoring of SPP’s members. The updating of § 7.3.1.3 (a) was critical to providing a clear and concise direction for the members to follow in order to maintain compliance to this standard. The questions answered by the update were:

What is the load that is used for the 10% step and total 30% calculations? Answer: The calculation is based on the current load at the time of the incident.

When must my UFLS program meet the criteria? Answer: At all times regardless of starting load point.

How can I meet the criteria? Answer: Install dynamically controlled relays that arm and disarm while following load or installing enough relays to meet the overall 30% goal but in increments shown in the chart inserted in § 7.3.1.3 (a). The term ‘Minimum Load Relief (%)’ was added to the chart.

Section 7.3.1.3 is the basis for member compliance to the NERC/SPP Compliance Program. The two SPP Working Groups responsible for the Criteria are the System Protection and Control Working Group (SPCWG) and the Operating Reliability Working Group (ORWG). Monitoring Techniques In 2000, the SPP Security Working Group [now the ORWG] conducted a summer time review of member’s UFLS program status. This survey was not used for measuring compliance to the SPP Criteria but as an informational survey for use by the SWG. This technique was being used in the ERCOT region and the SPP SWG agreed to perform the survey to determine its usefulness at SPP. The survey consisted of SPP choosing a specific hour on a specific day and having the individual members report their total load for that hour plus the amount of load that would have been shed at each of the three (3) designated frequencies. Calculations were made for each step of the program and reported to the members.

After the 2000 survey, the SWG directed the SPP Compliance Group to perform an annual UFLS survey, near peak load conditions, to monitor the SPP members’ compliance to the SPP Criteria. These compliance surveys have been performed each

R.W. Ciesiel 9/19/2005 1


peak season since 2001 and used to monitor compliance to the SPP Criteria. In 2002, the Compliance Group added a spring UFLS survey for several reasons. The spring survey information can be used by SPP to monitor off-peak conditions and member responses to Criteria as well as provide initial data input in the 5-year Region-wide UFLS performance study required by NERC Standards [the next scheduled study is in 2006]. The spring survey was also instituted in order to give members an opportunity to review their programs and fill in gaps or complete maintenance programs before the ‘compliance survey’ performed in mid-summer. The original NERC UFLS compliance template did not have an objective set of measures to determine compliance levels. Based on discussions with the SWG, the following compliance guidelines were established and published:

SPP APPROVED COMPLIANCE LEVELS (APPROVED BY SWG IN 2000)

100% COMPLIANCE - Met total requirements of 30% or greater load shedding and all

steps were greater than or equal to 10%. LEVEL 1 - Met total requirements of 30% or greater load shedding but one or more steps

were less than 10% LEVEL 2 - Total load shed was less than 30% but greater than or equal to 20% LEVEL 3 - Total load shed was less than 20% but greater than or equal to 10% LEVEL 4 - Total load shed was less than 10% These guidelines were used to assess compliance to the SPP Criteria for the 2001 through 2003 summer surveys. In 2004, the NERC Compliance Templates were re-written and approved for implementation on June 1, 2004. The UFLS template was revised to include more objective measures of a member’s compliance. The ORWG adopted the NERC levels of compliance for the 2004 UFLS survey and beyond. These levels of compliance are shown below:

Levels of Non-Compliance

Level 1 - Evaluations of entity UFLS programs for consistency with the Regional UFLS program were incomplete/inconsistent in one or more requirements of Measure III.D.M1 but is consistent with the required load shed.

Level 2 - The amount of load shedding is less than 95% of the regional requirements in any of the load steps.

Level 3 - The amount of load shedding is less than 90% of the regional requirements in any of the load steps.

R.W. Ciesiel 9/19/2005 2


Level 4 - The amount of load shedding is less than 85% of the regional requirements on any of the load steps, or evaluations of entity UFLS programs for consistency with the Regional UFLS program were not provided.

The major difference between the new NERC measures and the SPP measures is that for Levels 2 to 4 the NERC measures are pointed toward performance on individual steps versus the SPP measures the utilized total load shed as the measure. This makes the NERC standard more stringent than the SPP standard.

2004 Survey and Results The 2004 summer survey was conducted on August 26, 2004. The results were accumulated and subsequently presented to the ORWG for review. The results of the 2004 survey are attached. The recommendations for non-compliance included 6 members that managed to shed 30% or more of their initial load but did not meet the more stringent requirement of shedding a minimum of 10% at each step. These members were found to be at a Level 1 non-compliance because they met the overall goal of the 30% total but were inconsistent with the requirement to shed load at minimum of 10% steps. Letters of non-compliance were sent to members that were not in 100% compliance with the Criteria. In November 2004, Southwestern Power Administration [SPA] sent a letter to SPP asking for an appeal of the Level 1 finding. The SPP Compliance Group added the following members to the appeal because they each were in the same category as SPA: AEP West City of Clarksdale, MS City of Independence, MO City of Lafayette, LA Southwestern Public Service The SPP SPCWG and the SPP ORWG met separately in late 2004 and early 2005 to hear this appeal. These two working groups heard the appeal, reviewed the existing Criteria and published the following statement:

“The ORWG reviewed SPA's non-compliance appeal at its December 15-16 [2004] meeting. The ORWG is of the opinion that the appeal is without merit based on SPP Criteria 7 which clearly indicates that a minimum of 10% of load relief per step is required. This requirement is specified in the table included in Section 7.3.1.3.a and is referenced several times in Section 7.3.1.3.a. The ORWG noted that at least 4 previous UFLS surveys had been conducted based on this interpretation of Criteria and that even though survey results have been consistently similar to the August 2004 survey results, no questions had been raised regarding this issue.” [The SPCWG unanimously adopted this statement in early 2005 as its response to the appeal].

R.W. Ciesiel 9/19/2005 3


Upon notification that their original appeal had been denied, Southwestern Public Service [one of the original 6 members] asked for an additional level of appeal to the SPP Compliance Committee. The Compliance Committee granted the request for an appeal. SPP Compliance Group Analysis The SPP Compliance Group agrees with the analysis of the SPCWG and the ORWG that the wording of the Criteria is clear that compliance is met by shedding a minimum of 10% per step for a total of 30% or more. The appellants’ argument that the overriding intent of the Criteria is to achieve 30% load shedding without regard to the shedding at each step is negated by the words of the Criteria that state “[t]he relays shall be set to shed thirty (30%) percent total in increments of current load per step, as indicated in the chart below.” The chart then shows “Minimum Load Relief (%) ” as 10 for each step. Specific statements that qualify the meaning of general statements always trump the general statements of any criteria. The appellants also ignore the history of monitoring and measuring compliance for this standard. SPP guidelines for measuring compliance approved in 2000, and discussed above, included a requirement that 100% compliance was that each member “[m]et total requirements of 30% or greater load shedding and all steps were greater than or equal to 10%. All measurements of compliance from 2001 to 2003 used this requirement. The appellants also argue that the SPCWG and the ORWG have recognized that the Criteria should be modified to provide some flexibility in meeting the requirements of the Criteria. They state that the original appeal letter from SPA triggered a review of the Criteria and that changes that provide the requested flexibility are imminent. They also request that because a change was recognized and is imminent that they should be held to the revised standard rather than to the existing standard. The two SPP Working Groups are discussing language modifications that will provide some flexibility in meeting the requirements of the Criteria but have agreed on such language and there is no guarantee that any changes will be made in the future. Even if there are changes made to the Criteria, applying them retroactively is not in the best interest of the compliance program. If retroactive standards are applied in this case, setting a precedent, then all findings of compliance are subject to change when the rules change in the future. In order to move forward with the program from year-to-year, there must be finality to the findings, based on the standards in place at the time of the findings. In addition, the two groups that are now reviewing proposed language changes issued a very strong statement reflecting their views of the current Criteria and the rules of compliance [see above on page 4]. For these reasons, the SPP Compliance Group recommends that the non-compliance findings for the six members be upheld and confirmed. Respectfully submitted on July 29, 2005 by: Ronald W. Ciesiel SPP Compliance Director 501-614-3265

R.W. Ciesiel 9/19/2005 4

INDEPENDENT MARKET MONITOR REPORT

SPP BOARD OF DIRECTORS/MEMBER COMMITTEE MEETING

Santa Fe, NM October 25, 2005

I. COMPLIANCE COMMITTEE MEETING SEPTEMBER 28, 2005 IN CHICAGO

II. RESPONSE TO FERC ORDER (SEPTEMBER 19, 2005)

A. “Refinements and Explanations” B. Key Issues for Market Monitoring

1. Market-Based Rate Authority/Cost-Based Cap 2. Delineate IMM and MMU Responsibilities 3. Specific Questions

a. Address portfolio bidding b. Support mitigation for transmission market power c. Are scheduling penalties enough? d. Edit to comply with Policy Statement

III. INITIAL ASSESSMENT OF REMAINING COMPLIANCE AND MARKET POWER ISSUES RELATED TO THE PROVISION OF TRANSMISSION SERVICE

BOSTON PACIFIC COMPANY, INC.


FIRST DRAFT

INITIAL ASSESSMENT OF REMAINING COMPLIANCE AND MARKET POWER ISSUES RELATED TO THE PROVISION

OF TRANSMISSION SERVICE

Prepared by:

Boston Pacific Company, Inc.

Independent Market Monitor for the Southwest Power Pool, Inc.

October 14, 2005


COMMENTS ON AND CORRECTIONS TO THIS FIRST DRAFT ARE WELCOME

Comments from SPP Staff are currently being solicited. One or more stakeholder forums (teleconferences) will be held before the end of 2005 to solicit comments and corrections.

Contact: Please email your comments to

the Initial Assessment Coordinator at: [email protected]

or

Mail or Fax to:

Boston Pacific Company, Inc. 1100 New York Avenue, NW, Suite 490 East

Washington, DC 20005 Telephone: (202) 296-5520

Fax: (202) 296-5531

BOSTON PACIFIC COMPANY, INC. i

TABLE OF CONTENTS

I. PURPOSE AND SUMMARY................................................................................ 1

A. Purpose.............................................................................................................. 1

B. Summary ........................................................................................................... 1

II. ADDITIONAL BACKGROUND ......................................................................... 5

A. Defining Transmission Market Power .............................................................. 5

B. Mitigating Transmission Market Power............................................................ 5

C. SPP is Approved as an RTO ............................................................................. 6

D. FERC Revisits Order 888 ................................................................................. 7

E. Brief History of SPP’s Role in Transmission.................................................... 8

III. THE EXISTING TRANSMISSION SYSTEM...................................................... 9

A. How Much Electricity Can the Transmission System Deliver? ....................... 9

1. Determining Available Transfer Capability (ATC) and Available Flowgate Capacity (AFC)........................................................................ 9

2. Areas of Concern ................................................................................... 13

3. Approving Reductions in Capacity Due to Maintenance ...................... 14

B. What Types of Transmission Service Are Available?.................................... 15

1. Point-to-Point Transmission Service ..................................................... 15

2. Network Integration Transmission Service ........................................... 17

C. How Is Transmission Service Arranged? ....................................................... 18

1. The Transmission Reservation Process ................................................. 18

2. The Transmission Scheduling Process................................................... 22

D. Who Loses Service (Who Is Curtailed) When the Transmission System Becomes Congested? ...................................................................................... 23

1. The NERC Transmission Loading Relief (TLR) Process...................... 23

E. How Do Rules for the New Energy Imbalance Services (EIS) Market Affect All This?.......................................................................................................... 26

1. Broadening the TLR Process ................................................................. 26

2. Areas of Concern ................................................................................... 28

IV. EXPANDING THE TRANSMISSION SYSTEM ............................................... 30

A. How Are Investments to Expand the System Identified and Funded? ........... 30

1. Reliability Upgrades .............................................................................. 30

2. Economic Upgrades ............................................................................... 32

BOSTON PACIFIC COMPANY, INC. ii

3. Areas of Concern ................................................................................... 35

B. The RSC’s View on the Importance of Upgrades to Congestion Management 35

1. The Importance of Base Plan Upgrades................................................. 36

2. The Role of Economic Upgrades........................................................... 37

C. How Are New Power Plants Interconnected to the Transmission System? ... 37

1. Interconnection Request......................................................................... 38

2. Interconnection Feasibility Study Procedure ......................................... 39

3. Interconnection System Impact Study Procedure .................................. 39

4. Interconnection Facilities Study Procedure ........................................... 40

5. Standard Large Generator Interconnection Agreement ......................... 40

6. Cost Responsibility ................................................................................ 40

7. Areas of Concern ................................................................................... 41

BOSTON PACIFIC COMPANY, INC. 1

I. PURPOSE AND SUMMARY

A. Purpose

In an Order dated February 10, 2004, the Federal Energy Regulatory Commission (FERC) granted Regional Transmission Organization (RTO) status to the Southwest Power Pool (SPP) subject to certain requirements.1 Among those requirements was the requirement to have an Independent Market Monitor (IMM) in place with duties related to the provision of transmission service.2 FERC noted that, as proposed by SPP, among the IMM’s duties was the duty to “oversee the safe and reliable operation of [SPP’s] transmission system.”3 FERC went on to explain the IMM would report “on compliance and market power issues (including compliance and market power issues involving congestion management and ancillary services and the potential of any market participant(s) exercising market power within the region by affecting available transfer capability.)”4 The purpose of this report is to let everyone know upfront the IMM’s remaining areas of concern with respect to compliance and transmission market power, and therefore, the areas that will be monitored more closely going forward. (We use the term remaining because, clearly, the creation of the SPP RTO is in-and-of-itself good progress toward compliance and market power mitigation.) To identify these remaining areas of concern, we conducted a review (an initial assessment) of SPP practices to (a) determine transmission capability, (b) grant transmission service, (c) manage congestion, and (d) expand the transmission system. In addition to leading us to the areas of concern, we hope the initial assessment also will make some SPP practices more transparent and may lead to best practices being revealed and adopted.

This First Draft of the Initial Assessment will be reviewed by SPP Staff and taken through a stakeholder process by the IMM to be sure we have gotten our facts straight and to hear feedback on our areas of concern. This First Draft is done to the best of our knowledge at this time. Given the rapidly changing environment within the SPP system, reviewers of this draft should be aware that practices change and the concerns raised herein may already have been addressed.

B. Summary The successful creation of the SPP RTO, in-and-of-itself, is a big step toward (a) complying with FERC requirements for transmission service and (b) mitigating transmission market power. The SPP RTO promotes all three key elements of 1 See Order Granting RTO Status Subject to Fulfillment of Requirements in FERC Docket No. RT04-1 on

February 10, 2004 (“Order Granting RTO Status”). 2 Ibid at pp. 2 and 52, footnote 201. 3 Ibid at p. 52. 4 Ibid at p. 52, footnote 201. Other relevant IMM duties listed by FERC includes monitoring for “any

behavior that hinders the reliable, efficient and non-discriminatory provision of transmission service by SPP; ensuring SPP’s involvement in markets does not discriminate in favor of any market participant or its own interests.”


compliance and mitigation: separation, transparency, and comparability. [These are benefits over and above the other benefits of establishing an RTO. The elimination of “pancaked” transmission rates is chief among these other benefits. Now, when power is sold across multiple utility areas, rather than pay an accumulation of rates for all areas (a pancaked rate), transmission customers pay a single rate for the destination zone of the power transaction.] The SPP RTO promotes separation of decisions on transmission from those on generation to the extent it meets three key FERC requirements: (a) transmission owners yield operational control of transmission facilities to SPP, (b) SPP is the sole transmission provider; and (c) SPP determines the projects in and priorities of the transmission plan. Since SPP remains a member-driven organization, the fact the SPP RTO is governed by an independent Board of Directors further enhances separation.5 SPP promotes transparency through its OASIS site, through an open stakeholder process and through publicly available written documentation. With things changing rapidly, it is difficult to keep documentation up-to-date. We wrote this First Draft almost solely with publicly available documentations, so SPP clearly has made a good effort. Going forward SPP will have to provide more complete and clear documentation for all aspects including internal practices related to transmission service.6 Comparability is central to assuring that consumers get the best deal possible when generators compete. SPP RTO has made progress here, too. However, of the three key elements of compliance and mitigation, comparability is the most difficult to monitor and judge. For that reason, it must be a primary focus for the IMM going forward. Again, since the SPP RTO represents progress in all respects, the following is best viewed as a list of remaining areas of concern about compliance and transmission market power system based on the IMM’s Initial Assessment.

• We accept that SPP must and should interact with transmission owners to assure reliable system operation. However, with respect to determining how much transmission capability exists, transmission owners still have important input into calculations of Available Flowgate Capacity (AFC) and Available Transfer Capability (ATC). That input should be monitored going forward potentially through a system of routine screens developed with SPP Staff.

• We note that eleven of seventeen control areas have placed some or all service

under SPP’s OATT. Going forward, we want to understand what differences in coverage across the region have on markets and whether more complete coverage under SPP’s OATT is possible and, if so, whether it would benefit consumers.

5 See Order Granting RTO Status at pp. 1-2 and 52. Note that FERC requires that the IMM report directly

to the Board of Directors. 6 FERC made a similar point in its recent order. See Order on Proposed Tariff Revisions in FERC Docket

No. ER05-1118-000 on September 19, 2005 at pp. 8-9.


• For the control areas that have placed some service under the SPP OATT,

transmission owners, not SPP, are still often responsible for processing some Network Integration Transmission Service (NITS) requests. Going forward, we would like to know if it would be beneficial for SPP to do more.

• Transmission owners conduct or have significant input into transmission

studies that determine what it would take (system upgrades, redispatch, etc.) to fulfill a transmission service request. This, too, is an area to monitor transmission market power going forward and a potential area for checks and balances to be established.

• We could not find documentation that SPP has the right to and a process for

verifying transmission forced outages. If it does not, SPP should have such a right and should put in place a process for verification.

• Today, SPP manages congestion only on flowgates. Flowgates are critical

parts (elements) of the transmission system that represent a potential constraint to power flows. Other congestion is managed by control areas. One area of concern is that control areas designate flowgates and, thereby, determine the extent of SPP’s congestion management effort.

• With respect to congestion management in the future, the introduction of the

Energy Imbalance Services (EIS) Market could lead to significant changes because it could reveal the extent of congestion more fully. New computer tools such as the Network Load Scheduler (NLS), Market Flow Calculator, and the Curtailment Adjustment Tool (CAT) will be key to congestion management. No one can fully assess the effects of the tools until market trials are complete and market operation begins. Our focus will be on comparability. For example, does the new congestion management system treat different suppliers comparably especially with respect to assignment of transmission priority?

• The issue of who faces additional transmission charges for EIS appears to be

unresolved. We would like to see and review a resolution.

• Going forward, we expect to see and to review significant SPP business practices for comparability. We mentioned the new approach to congestion management above. Another, example might be the new zonal approach to assessing transmission reservation requests.

For transmission expansion, the IMM notes that the Regional State Committee

(RSC) has led significant progress on crucial issues (all with hard work by SPP Staff and important input from stakeholders). The issues, simply put, are (a) which transmission upgrades should be made? and (b) who should pay for them? These are crucial issues nationwide since most agree new transmission investment is needed. Since we believe


shortages of any infrastructure create fertile ground for market power abuse, the RSC’s progress on setting the rules for new transmission investment is an important mitigation effort. The RSC splits investments into reliability upgrades and economic upgrades. Reliability upgrades are those needed, in effect, to assure the lights stay on. SPP identified reliability upgrades during the first year of a two-year process. With respect to who pays, FERC already has approved a cost allocation plan proposed by SPP. One-third of the cost of reliability upgrades will be paid by all SPP transmission customers (region wide) and the other two-thirds will be paid by the areas in which the power actually flows (a Megawatt-mile method). Economic upgrades are those needed to take advantage of new, lower cost power. The process is not complete in this regard. The definition of an economic upgrade is unsettled. It appears to be settled that project sponsors will pre-pay (participant fund) the costs of the investment and then get a credit on charges for transmission service reflecting the prepayment. The remaining issue is whether this is enough to entice investment, or whether a first priority for use of the new facilities must be added. With respect to generator interconnection, we note that progress has been made by FERC requiring standardization of relevant agreements. An area of concern is that a transmission owner has input into related studies. In recent testimony to FERC, the RSC explained how its approach to upgrades is central to physical transmission rights (PTRs). We note that the SPP RTO proposed that a second phase of market development might cover market-based congestion management such as the use of financial transmission rights (FTRs), including a cost benefit study of such implementation. In response, FERC asked for the IMM to “conduct analysis to support this effort.”7

7 See Order Granting RTO Status at pp. 40 and 56.


II. ADDITIONAL BACKGROUND A. Defining Transmission Market Power

Transmission market power is typically characterized as vertical market power.

That is, the market participant must control both transmission and generation facilities, and then use the control of transmission facilities to favor its generation at the expense of those of competing generators. It often is said that this means the market participant forecloses its competitors.

Foreclosure can be illustrated with these three examples. First, the transmission owner can make it appear that transmission service is unavailable to competitors. This can be achieved by underestimating the amount of transmission capacity available – underestimating available transfer capability (ATC) or available flowgate capacity (AFC), for example. Second, a transmission owner can increase the risk of taking power from a competing supplier; for example, it can cause a competing supplier to bear more than its fair or correct amount of curtailment when transmission facilities are congested. Third, the transmission owner can make transmission service more expensive for its competitors; for example, it can overestimate the extent of transmission system upgrades needed to assure reliable delivery of power from a new power plant (system upgrades for a non-affiliated designated network resource (DNR)).

B. Mitigating Transmission Market Power

With respect to mitigation of transmission market power, starting on a case-by-

case basis in 1988, FERC consistently remedied transmission market power (undue discrimination) by requiring transmission owners to assure open access to transmission facilities for wholesale competitors.8

In 1996, in its Order 888, FERC codified this by requiring all public utilities to adopt variations of a pro forma Open Access Transmission Tariff (OATT). Order 888 established many requirements for transmission providers/transmission owners, but these can be summarized in three principles (a) comparability, (b) transparency, and (c) separation of the power generation and transmission sides of the utility business.9

Comparability was reflected in Order 888 with requirements such as that for transmission owners to “take wholesale transmission service under the same tariff” as offered to competitors.10

8 See Opinion 318 and Order in FERC Docket No. EC88-2 on October 26, 1988 and Order No. 888:

Promoting Wholesale Competition Through Open Access Non-discriminatory Transmission Services by Public Utilities and Recovery of Stranded Costs by Public Utilities and Transmitting Utilities in FERC Docket Nos. RM95-8-000 and RM94-7-001 on April 24, 1996 (“Order 888”) at pp. 25-29.

9 See Order 888 at pp. 11-12 and 22-24. 10 See Notice of Inquiry: Preventing Undue Discrimination and Preference in Transmission Services in

FERC Docket No. RM05-25-000 on September 16, 2005 (“NOI”) at p. 3.


Transparency was reflected in Order 888 and its companion Order 889 with requirements such as that for transmission owners “to create or participate in an Open Access Same-Time Information System (OASIS) that provides existing and potential transmission customers the same access to transmission information.”11

Separation was reflected in Orders 888 and 889 with requirements such as those to post separate rates for generation, transmission, and ancillary services as well as in standards of conduct governing communication between utility personnel in the transmission and generation sides of the business.12

An important backdrop for all attempts to promote open access is what is termed “native load priority” or preference.13 In effect, transmission service for the utility to serve its regulated retail customers has priority over uses of the transmission system for wholesale purchase and sales. Native load priority was reinforced by Congress in the Energy Policy Act of 2005 (EPAct 2005).14

Order 888 is said to have required functional unbundling of generation and transmission. In late 1999, saying Order 888 was not enough to combat undue discrimination and preference, FERC went further to structural unbundling in its Order 2000.15 Order 2000 defined what would be required to create an RTO. Those requirements were summed up in four characteristics and eight functions. The four characteristics refer to: (a) independence; (b) scope and regional configuration; (c) operational authority; and (d) short-term reliability. The eight functions necessary for a RTO refer to: (a) tariff administration and design; (b) congestion management; (c) parallel path flow; (d) ancillary services; (e) OASIS; (f) market monitoring; (g) transmission planning and expansion; and (h) interregional coordination.16

C. SPP is Approved as an RTO

SPP has fulfilled the requirements FERC set for becoming an RTO and, in

addition, gained approval for a phased approach to market development. There were six requirements set out in the February 10, 2004 Order.17 The first was to put in place an Independent Board of Directors. The second requirement--to have an IMM--already has been noted. It is useful to draw out the other four as a backdrop for this report: (a) SPP must be the sole transmission provider; (b) SPP must have operational control over the appropriate transmission facilities within its footprint; (c) SPP must solely determine the projects (and their priority) in the transmission plan; and (d) SPP must execute a seams agreement with the Midwest Independent Operator, Inc. (Midwest ISO)

11 See NOI at p. 4, footnote 6. See Order 889: Open Access Same-Time Information System (formerly

Real-Time Information Networks) and Standards of Conduct in FERC Docket No. RM95-9-000 on April 24, 1996 (“Order 889”) at p. 1.

12 See NOI at pp. 3-4, footnote 6. 13 Ibid at p. 7. 14 See Energy Policy Act of 2005, Pub. L. No. 109-58, ¶ 1231, 1233 119 Stat. 594 at Section 1233. 15 See Order No. 2000 in FERC Docket No. RM99-2-000 on December 20, 1999 (“Order 2000”) at pp. 1-8. 16 Ibid at p. 5. 17 See Order Granting RTO Status at pp. 1-2.


As to a phased approach, SPP gained approval for three phases. Phase 1 included

the design and implementation of the real-time energy imbalance market (SPP’s Energy Imbalance Services (EIS) Market).18 Phase 2, at the time of the FERC Order, was expected to add “financial transmission rights for market-based congestion management;”19 Phase 3 would add an ancillary services market.20

D. FERC Revisits Order 888

After almost ten years (1996 to 2005), FERC has just issued a Notice of Inquiry

(NOI) on whether and how to reform Order 888 based on “lessons learned.”21 In that NOI, FERC revisits many basic decisions now embedded in the pro-forma OATT and in the OATTs of individual public utilities. Five examples of questions asked by FERC in its NOI illustrate the possible breadth of the changes that might be considered.

First, indicating that the functional unbundling of Order 888 is not enough to remedy undue discrimination, FERC asks if there is something other than structural unbundling that would help. Here FERC asks about (a) adding reporting requirements – such as reporting on denials of requests for transmission service,22 (b) standardizing practices – such as standardizing the calculation of available transfer capability (ATC); and (c) assuring comparability – FERC asks if the transmission provider serves native load with service comparable to non-affiliates who want to do the same under an OATT.23

Second, FERC notes that transmission network service cannot be resold and, therefore, the electricity business does not have the benefit of a secondary market for network service as does the natural gas pipeline business – the benefit is that limited gas pipeline capacity goes to the highest value. FERC asks if resales could be allowed. In the same context, FERC asks if it should allow more flexibility on pricing for re-dispatch and system upgrades. FERC suggests these pricing changes might be administered by an independent third party.24

Third, FERC asks if the contract path model and embedded cost ratemaking of Order 888 is still appropriate, or are alternative pricing approaches better?25

Fourth, FERC notes that while transmission customers are subject to penalties, transmission providers are not. FERC asks if it should use its new civil penalty authority

18 See Order Granting RTO Status at p. 39. 19 Ibid at p. 40. 20 Ibid at p. 40. 21 See NOI at p. 2. “The Commission’s preliminary view is that the pro forma OATT and public utilities’

OATTs should be reformed to reflect lessons learned during nearly a decade of the electric utility industry’s and the Commission’s experience with open access transmission.”

22 Ibid at pp. 10-11. 23 Ibid at pp. 11 and 15. 24 Ibid at pp. 12-13. 25 Ibid at p. 13.


under EPAct 2005 to impose penalties on transmission providers for violations of OATT or Market Behavior Rules.26

Fifth, the generation facilities a public utility dedicates to serving native load – DNRs – cannot make firm, off-system power sales. FERC asks whether DNRs should be able to make such sales.27

E. Brief History of SPP’s Role in Transmission

SPP began as eleven companies voluntarily joining together during World War II (in 1941) to meet the Nation’s national defense needs. Subsequently, SPP formed a reliability council in order to help its members “Keep the lights on.” During those years, SPP’s primary responsibility was helping to coordinate the reliability of the transmission systems of its members. The transmission systems themselves were still owned and controlled primarily by vertically integrated utilities.

Today, SPP has grown into a FERC-approved RTO covering seventeen control

areas, 255,000 square miles of area, 52,301 circuit miles and 33,000 miles of transmission lines.28 Of those seventeen different control areas, eleven have placed some portion of their OATT services under SPP’s OATT. This is a significant step forward in SPP being the transmission provider. Of the six control areas that are not under the SPP OATT, three are transmission dependent utilities; two are non-FERC jurisdictional entities, and the sixth and final entity is an investor-owned utility. A more detailed description of the SPP members and their roles is provided in Attachment One.

As a FERC-approved RTO, SPP has operational authority over its members’

transmission systems as it has demonstrated in its Operational Authority Reference Document to FERC.29 While SPP monitors the entire system of lines for reliability purposes, it only monitors congestion on a daily basis on designated flowgates. The SPP footprint consists of 2,533 transmission lines and transformers.30 Roughly 177 (or 7%) of those elements constitute flowgates.31 Other congestion is presumed to exist and to be managed by the control areas.

26 See NOI at pp. 17 and 28. 27 See NOI at pp. 31-2. 28 See http://www.spp.org/About_Main.asp. See Attachment 1 for a list of SPP Control Areas and

Members. 29 See SPP’s Control Area Consolidation Feasibility Study in Southwest Power Pool, Inc. in FERC Dockets No. RT04-1-000 and ER04-48-000 on February 11, 2004 at p. 1. 30 See SPP Summer Peak 2005 Transmission Model. These are transmission lines and transformers that are

greater than 69kV. 69kV Transmission elements are still used for transmission, but typically are within specific control areas. Transmission elements smaller than 69kV are regarded more as distribution elements and lie entirely within control areas.

31 See SPP OASIS. No flowgates consist of transmission lines 69kV or below. Note, this does not mean that flowgates only carry 7% of the power crossing the SPP footprint.


III. THE EXISTING TRANSMISSION SYSTEM

A. How Much Electricity Can the Transmission System Deliver?

1. Determining Available Transfer Capability (ATC) and Available Flowgate Capacity (AFC)

Available Transfer Capability (ATC) quantifies the ability of the transmission system to safely transfer power from one point to another. Specifically, it is the portion of Total Transfer Capability (TTC) that is available to serve wholesale customers after deductions have been made for (a) transmission service needed by transmission owners’ to serve their retail customers and (b) transmission reserved to assure system reliability/stability.32

Traditionally, ATC has been determined by the vertically integrated utility. Because the utility controls both generation and transmission, there was a market power concern. The concern is that the utility would understate ATC. By doing so, the utility might favor affiliate generators by denying ATC to competing generators.33 Since being formed as an RTO, SPP has seemingly removed the ability for market participants in its footprint to discriminate against competing generators in this manner because SPP calculates ATC across the region.34 However, there are several factors used in determining ATC in which transmission owners still have significant inputs, such as transmission line ratings. This input is necessary since utilities own these lines and are in the best position to analyze them. At the same time, this reliance leaves the door open for opportunities to exercise market power. These opportunities are explained in this section.

a. Designating Flowgates ATC calculations depend crucially on the calculation of Available Flowgate

Capacity (AFC). As noted, flowgates are simply a combination of critical transmission elements that represent a potential constraint to power flow over the system. Consequently, they serve as a proxy for the entire SPP transmission system.35 Flowgates are typically just a pair of transmission lines. One of those lines is the limiting element and the other is the contingent element. The limiting element is usually at either the same or a lower voltage level than the contingent element. The amount of power-flow permitted over a flowgate is determined by examining the amount of power the limiting

32 See Comment of the Federal Trade Commission in FERC Docket No. RM05-17 on August 22, 2005

(“FTC Comment”) at p. 4. 33 Ibid at p. 2. 34 Note that according to SPP Criteria the Transmission Owners calculate ATC for transactions within their

area. See Southwest Power Pool Criteria April 26, 2005 Revision (“SPP Criteria”) at section 4.0. 35 See SPP Criteria at section 4.1.9.

KEY POINTS ON ATC/AFC

1. SPP calculates ATC/AFC- the measures of transmission capacity available for wholesale competition

2. Transmission owners provide input to ATC/AFC calculations

3. Transmission owners designate flowgates


element can transfer if the contingent element experiences an outage. This is the Total Flowgate Capacity (TFC). Some flowgates consist of only one transmission element that is limiting individually, absent a contingent element.36 In total, there are currently 89 flowgates within the SPP footprint.37

SPP manages access to these critical elements in an effort to keep outages from occurring and power flowing smoothly over the system. Consequently, the process by which they are designated is very important. Transmission owners are usually the entity that designates a flowgate.38 Any time throughout the year, a transmission owner may require that a set of facilities be designated as a flowgate, regardless of ownership of that set of facilities, in order to ensure reliability or safety of equipment.39 Transmission owners, the SPP staff and stakeholder groups -- such as the Transmission Working Group (TWG) and the Operating Reliability Working Group (ORWG) -- are responsible for reviewing and monitoring the entire list of flowgates. In addition to these periodic reviews, the flowgate list will be reviewed annually by the TWG using seasonal power flow models. The purpose of this review is to assess the adequacy of the existing list and therefore recommend any necessary additions, deletions, or changes.40 As stated earlier, it is ultimately these flowgates and their available capacity that determines ATC.

b. Calculating Available Flowgate Capacity (AFC)

After designating flowgates the next step is to establish the amount of available

capacity over those flowgates. This process has several steps and is mathematically defined as:41 AFC = TFC – FBL – TRM42 Where: AFC = Available Flowgate Capacity, TFC = Total Flowgate Capacity,

36 There are other combinations of lines that constitute a flowgate; however, the basic structure discussed

here is the most common and will suffice. 37 See SPP OASIS at http://sppoasis.spp.org/OASIS/SWPP. 38 SPP reliability personnel designate temporary flowgates to manage congestion arising from unforeseen

circumstances, such as severe weather. 39 See SPP Criteria at section 4.4.1. There are certain types of flowgates that require Transmission Working

Group (TWG) and Operating Reliability Working Group (ORWG) approval; however, these types are unusual and do not include the more common types. SPP, as the reliability coordinator, can also work with transmission owners to designate flowgates in the event of significant topological changes to the system.

40 See SPP Criteria at section 4.4.2. 41 See SPP Criteria at section 4.2.8.2. 42 SPP only uses a Transmission Reserve Margin. What is traditionally thought of as a Capacity Benefit

Margin (CBM) is TRM in SPP. See SPP OATT, Attachment C at p. 120. Note that the equation for calculating AFC and ATC is the same; AFC is just restricted to a particular flowgate while ATC is for an entire transaction (from a specific point (source) to another point (sink)). See NERC Available Transfer Capability Definitions and Determination June 1996 at p. 2.


FBL = Flowgate Base Loading, and TRM = Transmission Reserve Margin. The remainder of this section is organized by discussing each of the independent variables in turn. Total Flowgate Capacity (TFC) as mentioned briefly above, is the amount of capacity that the limiting element of a flowgate can safely transfer. It is determined by the rating of that limiting element – the three types of ratings are stability, thermal, and voltage limits.43 Any of the three limits can determine the TFC given the circumstances at the time. Stability limits are established so the network is capable of surviving disturbance. Thermal limits are the maximum amount of electrical current that can safely flow over a transmission element. The voltage limit of a line is range of levels of use that keep voltages within an acceptable range. Transmission owners calculate and submit these ratings to SPP. They are required to submit two ratings – a normal rating and an emergency rating. The normal rating specifies the amount of power that a transmission facility can continuously carry without damaging equipment. The emergency rating indicates the permissible power flow (with acceptable loss of life to the facility) while adjustments are being made to correct the situation.44

The actual limits can be affected by ambient weather conditions such as temperature, wind speed, and wind direction.45 Despite these factors, transmission owners are only required to calculate winter and summer seasonal ratings. They may elect to calculate a third set of seasonal ratings for the shoulder months, but if they do not choose to do so, SPP will use the summer ratings for these months. It is also important to note that transmission owners can choose to use either the average or maximum ambient temperature of these seasons.46 This is important because the higher the temperature, the lower the limit (i.e., lower TFC). Flowgate Base Loading reflects existing transmission service commitments that control areas have for the purpose of serving network load. They are basically flows resulting from DNRs.47 SPP uses control area forecasts to determine the amount of base load for two different time periods: base load for more than one week into the future and base load for the next seven days out.

Each day, all control areas are required to submit an hourly load forecast for the following seven days. These forecasts are used to determine base loads for both time

43 See SPP Critera at section 4.2.4. There are also contractual requirements, which are reviewed by the

appropriate regulating agencies. 44 See SPP Criteria at section 12.2. 45 See FTC Comment at footnote 28. 46 See SPP Criteria at section 12.2. 47 Base Flowgate Load also includes the sum of positive impacts from Firm and Non-Firm OASIS

Commitments, Confirmed, Accepted, and Study. Firm Base Load includes 100% of Counter Impacts due to Confirmed Firm OASIS Commitments for DNR only. Non-Firm Base Load includes up to 50% of Counter Impacts due to Confirmed Firm OASIS Commitments. See SPP Criteria at sections 4.5.10.1 and 4.5.10.2.


periods. From them, SPP creates a default load forecast profile to determine FBL for more than seven days out. SPP updates this profile monthly. SPP also uses these forecasts and a tool called Load Forecast Lite (LFLITE) to determine base flows for the next seven days. LFLITE uses a tool called Nostradamus to fill in any gaps in the control areas’ forecasts; that is, if a control area only includes 2 days out in its forecast, Nostradamus will fill in the following five days based on historical data.48

SPP is in the process of creating two other tools to more accurately forecast load. The first is called the Mid-Term Load Forecast (MTLF). This is performed hourly for 7 days out, like the LFLITE. It too relies on the control area load forecast; however, the MTLF incorporates the last hour’s actual megawatt-generation to create a more accurate forecast. It also incorporates the last hour’s snapshot weather. The second tool is the Short-Term Load Forecast (STLF). This tool calculates the forecast every 5 minutes for one hour out. The STLF combines the MTLF forecast with the last 4-second actual megawatt-generation to obtain a smooth forecast. This process is completed fifteen minutes prior to the forecasted time; that is, the forecast for the eleven o’clock load is performed at 10:45.49 The Transmission Reserve Margin (TRM) is the “amount of flowgate capacity necessary to ensure that the interconnected transmission network is secure under a reasonable range of uncertainties in system conditions.”50 SPP calculates TRM in order to account for generation outages. If a generator goes offline and a reserve sharing event occurs, each flowgate has a margin of capacity that is guaranteed to be available in order to transfer the reserve power. This is the TRM. SPP determines it by assessing, at least annually, the “transmission impact of the outage of each generating unit within the SPP Transmission System…The capacity necessary to accommodate the greatest impact expected on each constrained facility is set aside as TRM.”51

c. Determining AFC and ATC

Available Flowgate Capacity (AFC) is the result of subtracting the FBL and TRM from the TFC. However, there are two different types of AFC, firm and non-firm. Firm AFC is calculated just as the equation above shows. non-firm AFC can actually be sold into the TRM.52 The reasoning behind this is that if a constraint or outage occurs and a reserve sharing event takes place, non-firm transactions are going to be curtailed. Therefore the TRM will be upheld.

It is important to note that the AFC calculation is the same as the ATC

calculation, just on a smaller scale. AFC is discussed because that is what ultimately 48 See Load Forecasts Overview at

http://www.spp.org/SPPTraining/TrainingInfo/MarketsforIT/LoadForecastsOverview.pdf. 49 See SPP Presentation “Load Forecasting for Reliability and Market Applications” by Mike Crosby to

MITF on 9-14-05. 50 See SPP Criteria at section 4.1.30. 51 See SPP OATT, Attachment C at pp. 120-126. 52 See SPP Criteria at section 4.3.3. The actual amount of TRM that can be sold depends on when the

request is made: the planning or the operating horizon.


limits ATC; however, when requesting transmission service, a market participant requests (and SPP calculates) ATC. ATC is reserved on a first-come first-serve basis respecting priority; that is, a firm request takes precedent over all non-firm requests, and a weekly non-firm request takes precedence over all daily non-firm requests, and so on.53 SPP automatically calculates ATC through a process called OASIS Automation. “OASIS Automation is integrated with SPP’s energy management system and uses power flow models developed from real time data.”54 The ATC calculation is done differently depending on which horizon the process is in, the planning or operating horizon. The planning horizon is for 2 to 31 days out while the operating horizon is for the next day. In the planning horizon, both firm and non-firm ATC are calculated as explained above. There is a review process for the ATC calculation. TWG, at the time of its annual flowgate review, conducts a review of the ATC determination process, including TRM, to ensure compliance with NERC requirements and reliability needs. SPP also conducts a survey of transmission owners and transmission customers so they can express their concerns with the process.55

2. Areas of Concern The creation of SPP as an RTO is a significant step forward in ensuring the

capacity available for competitors is accurately calculated and the method of calculating ATC is standardized for the SPP region. With those issues resolved, the remaining areas of concern are in (a) the flowgate designation process and (b) the calculation of each component of the ATC/AFC equation.

a. Designating Flowgates

Since transmission owners have the power to designate a flowgate, they also can

refrain from designating a flowgate; that is, they can manage transmission over a particular line on their own, without SPP oversight. The concern is that by managing their own congestion, control areas can negatively impact their competitors’ access to the system. This has the potential to become a much larger issue once the EIS market (and subsequently, a day-ahead market) is functioning. It is possible that the new market will reveal more constraints.

The goal is equal treatment in the designation of flowgates. As the transmission owners are responsible for designating flowgates, a potential area of concern would be that the owner designates a flowgate which results in the curtailment of a competitor and/or does not designate a set of lines as a flowgate for its or its affiliate’s generation, but rather chooses to redispatch its system. It is noted that SPP and several working groups review the flowgate list annually which should help mitigate this concern. As the

53 These priorities are shown in more depth in Table 6. 54 See SPP OATT, Attachment C at p. 121. 55 See SPP Criteria at section 4.5.11.


market evolves, SPP may also need to create standards by which flowgates are designated.

b. ATC Variables Transmission owners still have an impact on the calculation of ATC and AFC because they provide key inputs. For example, SPP relies on transmission owners’ line ratings to determine TTC. SPP also relies on control area load forecasts to determine the amount of FBL used in the ATC calculation.

While communication between SPP and transmission owners is necessary and

vital to ensure the reliable operation of the transmission system, in both cases discussed above the transmission owner is providing SPP with key inputs that could affect competitors. Going forward, developing a system of routine screens with SPP Staff may help to mitigate concerns with regard to the input provided by transmission owners and could also help to develop a set of best practices across SPP.

3. Approving Reductions in Capacity Due to Maintenance

Ensuring transmission reliability requires periodic planned maintenance of the transmission facilities. SPP must also handle sudden emergency outages, called forced outages, caused by equipment failures. Planned maintenance outages and forced outages require shifting power flow burden onto other transmission facilities. Thus each outage can reduce transmission capability over other transmission lines.

Reduced transmission capability creates the potential for reliability problems and can restrict some power producers from selling their generation into or out of isolated markets. A vertically integrated company that owns both a transmission system and generation may have the potential and the incentive to use both planned and forced transmission outages to foreclose rival generation sellers by denying them access to the wholesale power market.56

To prevent the use of planned transmission outages to exercise market power, SPP requires transmission owners to submit updated maintenance schedules on a daily basis.57 These schedules must be submitted to SPP at least one week in advance on a rolling-year basis.58 When a transmission owner requests scheduled transmission maintenance, SPP must provide an answer within two days of the request.59 If SPP determines that the transmission outage will adversely affect the electric transmission system, the transmission owners will need to find a way to minimize the impact or reschedule the maintenance.

56 See Order 2000. This Order addresses vertically integrated utilities’ abilities to exercise market power. 57 See Southwest Power Pool, Inc. Membership Agreement 2.1.3 April 26, 2005 revision (“SPP

Membership Agreement”) at 2.1.3. 58 See Southwest Power Pool Membership Agreement at section 2.1.3a. 59 See Southwest Power Pool Membership Agreement at section 2.1.3b.


a. Areas of Concerns

Forced transmission outages offer the same opportunity for an exercise of market power. However, forced outages cannot, of course, go through the same approval process as planned outages, but there could be an after-the-fact review to verify forced outages. SPP should be careful to confirm that forced outages are legitimate. Currently, there is no review process for verifying forced outages described in the SPP Criteria or SPP Membership Agreement. If SPP does not currently have this authority, even on a case-by-case basis, it could consider adding such a policy.

B. What Types of Transmission Service Are Available? One of the main objectives of FERC Order 888 is to eliminate the practice of “rate pancaking.” This refers to the situation in which a transmission customer pays multiple charges for moving energy through multiple electric systems. For example, if a customer wants to transmit energy to a load four systems away, it would have to pay four separate transmission charges. SPP eliminates pancaked rates by use of a zonal pricing system. Transmission customers pay service charges based on the zone in which their point of delivery is located and on the amount of power transmitted. Regardless of how many zones within SPP that the power flows through from source to sink, transmission customers only pay a single charge.60 For instance, if a customer wants to transmit energy from a generator in AEP’s service area to a load in OG&E’s service area, it would only pay the single charge associated with OG&E’s zone. Currently there are fifteen distinct zones, each with its own transmission rate. Transmission service through or out of SPP is charged the rate for the SPP zone that is directly interconnected with the control area of the point of delivery. If there are multiple zones directly interconnected then the transmission customer pays the lowest zonal rate.61

1. Point-to-Point Transmission Service There are two general types of transmission service available in SPP, point-to-point and network integration transmission service (NITS). Point-to-point service is pretty much what it sounds like: moving electricity from one specified point on the transmission grid to another specified point.62 The charge for point-to-point transmission service is straightforward in SPP. A transmission customer is simply charged a price equal to the rate of the zone in which the delivery point is located multiplied by the

60 See FERC Staff RTO-ISO Handbook Revised July 15, 2005 at Issue 5 – SPP Markets Operated by

ISO/RTO and Pricing at p. 2. 61 See SPP OATT, Schedule 7 at p. 103. 62 See SPP OATT at section 1.35 at p. 15. Point-to-point is for receipt of capacity and energy at designated

point(s) of receipt (POR) and the transmission of such capacity and energy to designated point(s) of delivery (POD).


amount of power.63 Table One displays the current firm point-to-point transmission rates for all of the SPP zones. Note that these rates were taken from the SPP OATT, but it does not mean that all entities are under SPP’s OATT. For example, it is our understanding that CLECO has not put its facilities under the SPP OATT.

Table 1

FIRM POINT-TO-POINT TRANSMISSION RATES64

On-Peak Off-Peak

Zone Company $/MW-Year$/MW-Month

$/MW-Week

$/MW-Day

$/MW-Day

1 American Electric Power1 1,050.00 241.64 48.33 34.52 2 Cleco Corporation 14,840.00 1,240.00 285.40 57.10 40.70 3 City Utilities of Springfield, Missouri 13,128.24 1,094.02 252.47 50.49 50.49 4 Empire District Electric Company 15,382.51 1,281.88 295.82 59.16 42.26 5 Grand River Dam Authority (Est.) 29,750.00 2,480.00 572.00 114.00 114.00 6 Kansas City Power & Light Company

For 345 and 161 kV Service 10,560.00 880.00 203.00 41.00 41.00 For 69 and 34kV Service 12,120.00 1,010.00 233.00 47.00 47.00

7 Oklahoma Gas & Electric Company 13,316.60 1,109.70 256.10 51.20 36.60 8 Midwest Energy, Inc. 24,506.70 2,042.20 471.30 94.30 94.30 9 Aquila Networks-MPS/L&P

For 345 and 161 kV Service 8,592.00 716.00 165.23 33.06 23.62 For 69 kV Service 19,332.00 1,611.00 372.16 74.43 53.17

10 Southwestern Power Administration 850.00 213.00 38.60 38.60 11 Southwestern Public Service4 19,200.00 1,600.00 369.00 62.00 62.00 12 Sunflower Electric Cooperative 53,800.00 4,480.00 1,034.60 147.80 147.80 13 Western Farmers Electric Cooperative 24,720.00 2,060.00 475.38 67.10 67.10 14 Westar Energy, Inc.2 15,600.00 1,300.00 300.00 42.70 42.70 15 Aquila Networks-WPK 11,736.00 978.00 225.89 45.18 32.27

1. Public Service Company of Oklahoma, Southwestern Electric Power Company, and SPP portion of Texas North Company

2. Kansas Gas & Electric and Westar Energy

3. For OG&E On-Peak Daily is Week day delivery and Off-Peak Daily is Weekend and Holiday Delivery.

4. Data for SPS was taken from SPP's OASIS website.

Delivery Point Yearly Monthly Weekly

Daily

These charges are for firm transmission for monthly, weekly, and daily service. These maximum rates are equal to the rates for firm point-to-point service. Table Two below shows the charges for non-firm point-to-point transmission service.

63 Note that in addition to the zonal transmission rate, transmission customers have to pay additional fees

for other services provided. See SPP OATT at Schedules 1-A through 6 at pp. 95-102 and Schedule 12 at p. 112B-C.

64 See SPP OATT, Attachment T at pp. 217-48.


Table 2

NON-FIRM POINT-TO-POINT TRANSMISSION RATES65

On-Peak Off-Peak On-Peak

Off-Peak

Zone Company$/MW-Month

$/MW-Week

$/MW-Day

$/MW-Day

$/MW-Hour

$/MW-Hour

1 American Electric Power1 1,050.00 241.64 48.33 34.52 3.02 1.44 2 Cleco Corporation 1,240.00 285.40 57.10 40.70 3.57 1.69 3 City Utilities of Springfield, Missouri 1,094.02 252.47 50.49 50.49 2.70 2.70 4 Empire District Electric Company 15,382.51 1,281.88 295.82 59.16 42.26 3.70 1.76 5 Grand River Dam Authority (Est.) 2,480.00 572.00 82.00 82.00 7.15 7.15 6 Kansas City Power & Light Company

For 345 and 161 kV Service 830.00 191.00 38.00 38.00 2.39 2.39 For 69 and 34kV Service 958.00 221.00 44.00 44.00 2.76 2.76

7 Oklahoma Gas & Electric Company 1,109.70 256.10 51.20 36.60 1.52 1.52 8 Midwest Energy, Inc. 2,042.20 471.30 94.30 94.30 5.60 5.60 9 Aquila Networks-MPS/L&P

For 345 and 161 kV Service 716.00 165.32 33.06 23.62 2.07 0.98 For 69 kV Service 1,611.00 372.16 74.43 53.17 4.65 2.22

10 Southwestern Power Administration 680.00 170.00 30.90 30.90 1.93 1.93 11 Southwestern Public Service 1,600.00 369.00 62.00 62.00 3.84 2.20 12 Sunflower Electric Cooperative 53,800.00 4,480.00 1,034.60 147.80 147.80 6.14 6.14 13 Western Farmers Electric Cooperative 2,060.00 475.38 67.91 67.91 2.83 2.83 14 Westar Energy, Inc.2 1,300.00 300.00 42.70 42.70 1.80 1.80 15 Aquila Networks-WPK 978.00 225.89 45.18 32.27 2.82 1.34



3. For OG&E On-Peak Daily is Week day delivery and Off-Peak Daily is Weekend and Holiday Delivery

Delivery Point Yearly Monthly Weekly

Daily Hourly

2. Network Integration Transmission Service SPP and various SPP transmission owners also provide NITS. SPP likens this to the kind of service a transmission owner would utilize to serve its own native load. Essentially, a network transmission customer designates its load and the generation resources it wants to use to serve that load. This is distinct from point-to-point service in that (a) no points of receipt or delivery have to be designated and (b) all network customers are directly serving load. Transmission customers pay for network service based on the zone in which their load is located. The network customer pays a monthly fee equal to its load ratio share times one-twelfth the Annual Transmission Revenue Requirement (ATRR) for that zone.66 The following table is a list of the ATRR for each zone.

65 See SPP OATT, Attachment T at pp. 217-48. 66 The load ratio share is the ratio of a NITS customer’s network load in a zone to the total load in that

zone.


Table 3

NETWORK INTEGRATION TRANSMISSION SERVICE ANNUAL REVENUE REQUIREMENT67

Zone CompanyExisting Zonal

ATRR1 American Electric Power1 88,681,579$ 2 Cleco Corporation 29,328,000$ 3 City Utilities of Springfield, Missouri 8,651,509$ 4 Empire District Electric Company 14,075,000$ 5 Grand River Dam Authority (Est.) 24,589,256$ 6 Kansas City Power & Light Company 35,461,776$ 7 Oklahoma Gas & Electric Company 65,065,032$ 8 Midwest Energy, Inc. 4,197,347$ 9 Missouri Public Service 18,884,642$ 10 Southwestern Power Administration 8,752,200$ 11 Southwestern Public Service SPS OATT12 Sunflower Electric Cooperative 19,637,429$ 13 Western Farmers Electric Cooperative 20,719,639$ 14 Westar Energy, Inc.2 Westar OATT15 Aquila Networks-WPK 5,947,002$



a. Areas of concern

Currently we do not have any areas of concern with the types of services offered in SPP. However, we would like to point out that it is key to ensure comparability in designating the generation resources that use NITS to serve customers.

C. How Is Transmission Service Arranged?

1. The Transmission Reservation Process An entity that wants to use the transmission system run by SPP will first make a Transmission Reservation on the SPP Open Access Same Time Information System (OASIS). SPP will aggregate requests for long-term firm point-to-point transmission service and DNR requests during a 120-day open season, and SPP will treat those requests as equal in determining ATC.68 If there is sufficient ATC on the system, the customer will be notified that SPP can handle its request. If there is not sufficient

67 See SPP OATT, Attachment H at pp. 161-161A. 68 DC tie lines are exceptions to this rule and are on a first-come first-served basis. See SPP OATT at

section 13.2 at p. 31.


capacity on the transmission system, SPP will initiate the System Impact Study Procedure.

SPP has proposed and implemented its first aggregate study process. The purpose of the study is to optimize the study process by choosing the least cost plan to accommodate all transmission requests. Specifically the SPP aggregate study process allows all long-term firm point-to-point and DNR requests received during the period to share (i) the costs of the transmission expansion and (ii) result in the least cost optimal transmission plan to accommodate all of the ATC request.69 We understand that the aggregate study process is a unique and new process to SPP that will likely have some issues as it develops. We want to ensure that over time this process appropriately allocates the cost and fosters the development of a competitive market. Please note that while most entities within SPP have relinquished the OASIS and the transmission reservation processes to SPP, not all entities have relinquished all services to SPP. Most of the transmission owners have transferred short-term firm or non-firm point-to-point service to SPP, but a few still ask the market participant to contact the transmission owner regarding NITS. The following discussion on the study procedures is based upon the SPP OATT; therefore, the timing and details may vary for those transmission owners within SPP for those services not under SPP’s OATT.

a. System Impact Study Procedure If SPP determines, on a non-discriminatory basis, that a System Impact Study (SIS) is needed, it will provide the Customer with a System Impact Study Agreement within thirty days of receipt of a completed application. The agreement binds the customer to reimbursing SPP for performing the SIS including any costs of the transmission owners.70 Once signed, SPP, in coordination with the affected transmission owners, will perform the SIS.71 This study identifies any system constraints associated with the transmission request, redispatch options and costs (if available), additional facilities (direct assignment facilities or network upgrades) required to provide the request.72 A series of computer models are used to evaluate the steady-state impact of the request and ATC under various conditions (spring, summer, fall, winter, and various load levels). The SIS will specify the actual not-to-exceed costs and time for completion of the study. 69 See SPP OATT, Attachment Z at p. 419. 70 See SPP OATT at section 19.1 at p. 54A. 71 See SPP OATT, Attachment D at p. 127. 72 Direct assignment facilities are those that are constructed by the transmission owner for the direct benefit

or use of a particular transmission customer, groups of transmission customers or a particular generation interconnection customer requesting transmission service. Network upgrades are additions or modifications to the transmission system that benefit all users. See SPP OATT at section 1.10 at p. 8.

STEPS IN SPP

RESERVATION PROCESS

1. Reservation Request 2. SIS Agreement 3. System Impact Study 4. Facilities Study Agreement 5. Facilities Study 6. Construction-Upgrades 7. On to Scheduling


After the transmission customer receives the SIS Agreement, the customer has 15 days to do the following or risk having its request terminated:

• Sign and return the System Impact Study Agreement

• Pay SPP a deposit equal to one month’s charge for reserved capacity or the full charge for less than one month; SPP has the option of waiving this requirement if the customer is creditworthy.

SPP, in coordination with the appropriate transmission owner(s), will use good

faith efforts to complete the required SIS within a sixty day period from the transmission customer’s execution of the SIS Agreement. Within 15 days of completion of the SIS the customer must execute a Service Agreement or the application will be terminated.

b. Facilities Study Procedure

The next step in the transmission reservation process after a reservation request is denied is the Facilities Study. This final study will provide for the customer a good faith estimate of the cost it will be charged for all necessary facility attachments and upgrades as well as an estimate of the time required to complete construction. Within thirty days of completion of the System Impact Study, the transmission customer is given a Facilities Study Agreement by SPP. Within fifteen days thereafter the customer must return an executed copy. As stipulated in the agreement, the customer agrees to reimburse SPP and any affected transmission owner for the cost of the study. When completed, the Facilities Study will include a good faith estimate of (i) the cost of direct assignment facilities to be charged to the transmission customer, (ii) the transmission customer’s appropriate share of the cost of any required network upgrades, and (iii) the time required to complete the construction and initiate the service request.73

Upon receipt of the executed Facilities Study Agreement, SPP, in coordination with the transmission owner(s), will use due diligence to complete the Facilities Study within sixty days.74 Once the study is completed and the assessment is provided, the transmission customer has thirty days to execute a Service Agreement and provide a letter of credit for the full costs of the new facilities or upgrades. SPP and the transmission owners will use due diligence to complete the upgrades within the stated time. Where the SIS or Facilities Study indicates that there is a need to construct direct assignment facilities to accommodate a request for transmission service, the transmission customer will be charged the full cost of such direct assignment facilities. There are four types of network upgrades (i) base plan (ii) economic upgrades, (iii) requested upgrades, and (iv) Generation Interconnection upgrades. A more detailed discussion of these upgrades is provided later in this report.

73 See SPP OATT at section 19.4 at p. 54. 74 Ibid.


A more detailed timeline of the reservation process is shown in Attachment Two.75

c. Areas of Concern One area of concern with the transmission reservation process is that some NITS

service requests and/or long-term firm requests appear to remain with the transmission owners. While we understand that the current procedure has been approved by FERC, we want to ensure that differences in coverage across the region do not adversely affect market participants. For reference, Table Four shows, for each SPP transmission zone, which services have been transferred under the SPP OATT as compared to those that have remained under the transmission owners’ OATT. It is worth noting that this is an initial assessment of the services and we will update this information as the report is reviewed by SPP Staff and stakeholders. One possible plausible reason for the owners retaining an OATT could be grandfathered agreements.

Table 4

LIST OF SPP ZONES AND SERVICES UNDER SPP’S OATT76

Zone CompanySPP

OATT?Control Area SPP

1 American Electric Power1 PartialYearly Firm, Some Network Service

Short-term Firm and Non-Firm (<1yr)

2 Cleco Corporation N All requests3 City Utilities of Springfield, Missouri Y All requests

4 Empire District Electric Company Partial All other requestsShort-term Firm and Non-

Firm P-t-P5 Grand River Dam Authority Partial Kamo P-t-P OATT All requests6 Kansas City Power & Light Company Partial Network Load All other requests7 Oklahoma Gas & Electric Company Y All requests8 Midwest Energy, Inc. Y All requests9 Aquila Networks-MPS/L&P Partial Network Service All P-t-P

10 Southwestern Power Administration 3 Y

Metered load from and electrically connected that does

not involve schedules All other requests11 Southwestern Public Service Y All requests12 Sunflower Electric Cooperative N All requests13 Western Farmers Electric Cooperative Y All requests14 Westar Energy, Inc.2 Y All requests15 Aquila Networks-WPK Partial Network Service All P-t-P

1. Public Service Company of Oklahoma, Southwestern Electric Power Company, and SPP portion of Texas North Company2. Kansas Gas & Electric and Westar Energy3. Separate Aggreement embedded in the OATT

Reservations

75 This is a re-creation of Attachment P to the SPP OATT. 76 See http://sppoasis.spp.org/OASIS/NODE/SPP.


Again, we believe that a fully functioning RTO, in and of itself, is a good first step to ensure that all parties are treated comparably. Going forward, we would want to know how the above differences in coverage could affect the region.

In addition, SPP’s OATT states that it will work in coordination with the affected

transmission owners in performing transmission studies. In performing the SIS, SPP will study the redispatch scenarios to accommodate the request for firm transmission, but only if the generating resources (transmission owners and others) are willing participants. The “willing participants” is an area of concern, because it raises the issue of comparability. That is, is redispatch offered on a fair basis to all parties? Further, input to the modeling is provided by the transmission owners. For example, in a presentation regarding SPP’s 2005 Aggregate Study 1, SPP stated that “Generation dispatch [was] based on dispatch orders received from transmission owners. For dispatch orders not received, dispatch was developed by staff using engineering judgment.”77

As the transmission owners have historically been the entities designing, building, and maintaining the transmission system it is logical that they provide some of the model inputs. However, going forward SPP in conjunction with the IMM should develop a set of checks and balances to ensure that the inputs and assumptions are valid. In addition, these checks and balances should help SPP to promote the development of best practices between transmission owners.

2. The Transmission Scheduling Process

Open access to the transmission system does not mean, of course, there is an unlimited ability to transmit power. A system has to be put in place to monitor the injections and withdrawals of power to judge what actual power flows the system can accommodate. The first step in the process is requesting a transmission reservation on OASIS. Once a reservation is confirmed, the transaction is given a set of “tags.” Tags are the result of an internet-based process that requests, secures approval of, and records an energy transaction (also known as Electronic Tagging or e-tag). The point of tags is to document all entities and physical assets or facilities involved in the energy transaction from the point of generation to the point of consumption.78 These tags are used to ensure that the power flow has valid settlement locations within SPP. Open Access Technology International, Inc., (OATI) is the company used for the tagging process and will automatically ensure that only SPP settlement locations that are mapped to NERC registered sources and sinks will be validated.79 Note that not all transactions need e-tags

77 See “2005 Aggregate Study 1 Presentation” on August 8, 2005 at

http://www.spp.org/Publications/CAWGagd&bkg090705.pdf at pp. 15-17. 78 See http://www.spp.org/Publications/Training_SubmChgsTagsResv.pdf. 79 Ibid.

STEPS IN SPP SCHEDULING PROCESS

1. Reservation Acceptance 2. Tagging Process- RTO_SS 3. Scheduling Submitted 4. COS & SPP Validation 5. Schedule Accepted 6. Power Flows 7. Settlement


as transactions that source and sink within the same control area are not required to have tags. As such, most transactions serving native load are not tagged.

For schedules between, through, or out of SPP control areas, after the transmission service reservation has been confirmed and a tag created, that information is electronically submitted to the SPP Regional Transmission Operator Scheduling System (RTO_SS). RTO_SS automatically creates a schedule from the transaction on the tag and then each party must confirm the schedule.80 Intra-control area schedules are not required to be part of the RTO_SS system, but can be created through the tagging process to aid control areas in their energy accounting. 81

After the RTO_SS process, schedules are validated using Commercial Operation

Systems (COS), an automated process provided by OATI. Tags are approved or denied based upon reliability issues and ATC. SPP schedulers monitor the COS validation results and approve those schedules based on a number of factors including: NERC policies, SPP tagging business rules, and SPP regional scheduling rules.82

In addition to the above process, the RTO_SS calculates and provides Net

Scheduling Interchange (NSI) for each SPP control area using the valid, approved schedules. NSI is the sum of all energy scheduled to flow into or out of the control area during a period of time.83 The Market Operations System (MOS) then calculates the energy imbalance NSI. 84 The MOS NSI and RTO_SS NSI are then combined and sent to the control area. Finally, the RTO_SS schedules that are settlement location specific are sent to the settlements.

D. Who Loses Service (Who Is Curtailed) When the Transmission System

Becomes Congested?

1. The NERC Transmission Loading Relief (TLR) Process Transmission loading relief (TLR) is a sequence of actions taken during either operations planning or real-time operation to avoid or remedy security violations resulting from transmission congestion, such as overloading that threatens the thermal limits of the transmission system. System planners and individual control area operators have traditionally developed systematic procedures, also known as “local” TLR, to assist in the avoidance or elimination of transmission loading problems. Typically the process is unique to each control area, and thus local TLR procedures may vary widely across the interconnected grid. NERC has also created a formal TLR procedure, shown below in

80 See EIS Market Interchange Scheduling Process Flow at SPP Glossary of Terms at www.spp.org. 81 See SPP Interchange Scheduling Job Aid (“Interchange Scheduling”) at p. 5 at

http://www.spp.org/TrainingToolKits/Courses/Scheduling/SchedulingJobAideHome.cfm. 82 Ibid at p. 6. 83 See Net Scheduled Interchange at SPP Glossary of Terms at www.spp.org. 84 MOS is a real-time system which performs Security Constrained Economic Dispatch (SCED), generates

set-point dispatch instructions for each resource, computes nodal price for each pricing node (generator or load location). MOS provides Ancillary Service (A/S) Plan, Resource Plan (RP), offer curve input and analysis functions. See Glossary at www.spp.org.


Table 5, to try to instill consistency and fairness in resolving issues of security that arise due to financial transactions. SPP utilizes this NERC TLR procedure when it detects security violations on its flowgates.85

The TLR process starts when a security coordinator, SPP, identifies a transmission facility within its security area that is about to exceed or will exceed its operating security limit. At this point the security coordinator will invoke TLR, which can be approximated by following sequentially the steps listed below for a NERC TLR.

Table 5

ACTIONS TAKEN DURING TLR LEVEL86

TLR level Reliability Coordinator Action System Status

TLR 1 Notify Reliability Coordinators of potential System Operating Limit (SOL) or Interconnection Reliability Operating Limit (IROL) violations System is Secure

TLR 2 Hold transfers at present level to prevent SOL or IROL violations System is Secure

TLR 3a Reallocation of Transmission Service by curtailing Interchange Transactions using Non-Firm Point-to-Point Transmission Service to allow Interchange Transactions using higher priority Transmission Service

System is Secure

TLR 3b Curtail Interchange Transactions using Non-Firm Transmission Service Arrangements to mitigate an SOL or IROL Violation

Security Limit Violation

TLR 4 Reconfigure transmission Any

TLR 5a Reallocation of Transmission Service by curtailing Interchange Transactions using Firm Point-to-Point Transmission Service on a pro rata basis to allow additional Interchange Transactions using Firm Point-to-Point Transmission Service

System is Secure

TLR 5b Curtail Interchange Transactions using Firm Point-to-Point Transmission Service to mitigate an SOL or IROL Violation

Security Limit Violation

TLR 6 Emergency Procedures Security Limit Violation

TLR 0 TLR concluded. System is Secure

There remain a number of limitations with the TLR process. First, TLR decisions can be inaccurate as they are based on the planning results of daily ATC and Power Transfer Distribution Factors (PTDFs) from the off-line computation. The shortcomings of ATC calculation generally were outlined in a previous section and include, for the purposes of TLR, the use of transmission schedules instead of actual transactions. Second, curtailment of transactions or reconfiguration of transmission can create new constraints on other facilities in the system. Third, the considerable demands of the iterative TLR process requiring coordination among several market participants and the rapid integration of large amounts of data in a short time period make it a difficult process to complete efficiently.

85 See Transmission Loading Relief (TLR) and Hour-Ahead ATC by Santiago Grijalva and Peter W. Sauer

at the 33rd Hawaii International Conference on System Sciences – 2000 at p. 2. 86 See NERC Operating Manual Dated August 8, 2005 (“NERC Operating Manual”) at Attachment 1-IRO-

006 (“Attachment IRO-006”) at pp. 4-7.


While invoking curtailment, SPP respects the reservation priorities of the

transactions. Transactions are curtailed in the order of lowest-to-highest priority. Transmission Service Priorities for energy schedules are ranked from zero to seven with higher numbers corresponding to higher priorities. Priorities in the range from zero to six are for non-firm services for varying durations. Firm transmission receives the highest priority. The complete list of Transmission Service priorities is summarized in Table 6.

Table 6

TRANSACTION SERVICE PRIORITIES87

Priority Level Transaction Type Priority Type

0 Next-hour Market Service – NX 1 Service over secondary receipt and delivery points – NS 2 Hourly Service – NH 3 Daily Service – ND 4 Weekly Service – NW 5 Monthly Service – NM

6 Network Integration Transmission Service from sources not designated as network resources – NN

Non-Firm

7 Firm Point-to-Point Transmission Service − F and Network Integration Transmission Service from Designated Resources – FN

Firm

It is noteworthy that because only a portion of a transaction’s power flow actually

affects any one flowgate, required relief is just a fraction of the power that actually has to be curtailed on the generating resource. For example, to provide 20 MW of relief on a flowgate, SPP might have to request that 100 MW of schedules are curtailed.

2. Areas of concern

While SPP’s TLR process is effective in maintaining transmission reliability, there exists the potential that a transmission owner, serving as the security coordinator for a control area, can favor its own generation during a TLR leading to opportunities for economic gaming. FERC is currently reviewing FERC Order 888 which addresses the communications between the transmission and generation entities in the market place. We believe FERC will improve the requirements under FERC Order 888, however, in cooperation with the MMU, we will monitor redispatching efforts for evidence of transmission market power and report to SPP and FERC accordingly.

87 See NERC Operating Manual at Appendix 9C1 Version 2b (“Appendix 9C1”) at p. A9C1-17.


E. How Do Rules for the New Energy Imbalance Services (EIS) Market Affect All This?

1. Broadening the TLR Process

Within SPP there will be two types of energy schedules once the EIS market is up and running. If a resource is self-dispatched, the schedule will be a physical schedule and if a resource is offered into the EIS for SPP dispatch or the resource is a settlement location for load, the schedule will be considered a market schedule. Self-dispatched resources are physical because the resource is assumed to physically operate at its stated MW level, while MW under the market schedule will be dispatched based upon SPP’s instructions.88 Because power will flow under these two different types of schedules, SPP needed to develop new methods for managing congestion.

Without the EIS Market, SPP would manage congestion on flowgates by

curtailing transactions through the NERC TLR process briefly described above. With the TLR process, certain transactions are reported to NERC. That is, they are “tagged” so the location of the generation (source) and its use (sink) are known. With source and sink, the transactions affecting any flowgate can be estimated and these are the ones curtailed if a flowgate becomes congested.

The NERC Interchange Distribution Calculator (IDC) is the tool used to record the tagged transactions and determines needed curtailments. The IDC generally focuses on transactions from one control area to another. That is, the level of detail (granularity) is at the control area.

With the EIS Market, congestion management will change significantly. For example, if the EIS Market itself is considered a control area, far fewer transactions will be reported to the NERC IDC. This is because the IDC does not go to a level of detail below the control area. In addition, even if tagged, the market flows may be substituted for scheduled/tagged transactions. Figure One below demonstrates a scenario where power will not flow from the source of a tagged transaction, but rather from an alternative generator. Assume Unit 1 in Control Area A has a bilateral contract with Control Area B, which is outside the SPP market footprint; therefore, by NERC guidelines, it will have an e-tag for that transaction. With the onset of the EIS market, Unit 1 could be offered into the EIS market. If Unit 2 in Control Area C (within the SPP market footprint) is cheaper than Unit 1, and offered into the EIS market, then Unit 2 would run and would serve Control Area B’s load even though Unit 1 had the e-tag. Unit 1 would then pay Unit 2 for running. NERC would not know that Unit 2 was serving Control Area B, thus if NERC needed to curtail transactions it would look to Unit 1. 88 See Southwest Power Pool Market Protocols Version 2.3a (“SPP Market Protocols”) at section 6.2.

KEY POINTS ON THE

AFFECTS ON EIS

1. The EIS Market could mean congestion is more fully revealed

2. New computer tools (NLS, MFC, CAT) will help to manage congestion

3. Comparability must be assured for market participants


Figure 189

To address these concerns, SPP has developed new software systems including the Native Load Scheduler (NLS), the Market Flow Calculator (MFC), and the Curtailment Adjustment Tool (CAT) to more accurately track and curtail the power flow occurring on the system. With these new tools, congestion management could be improved. Since there is a better level of detail (more granularity), curtailments affecting a flowgate could be more precisely identified. Moreover, with the EIS Market, re-dispatch becomes a more readily available alternative to curtailment as a means of congestion management.

Currently, SPP requires all scheduled injections to equal scheduled withdrawals

plus losses, but does not require the scheduling of all loads. Once the EIS market begins, SPP will need to know all loads to determine what is considered imbalance energy. Therefore SPP is developing the NLS which also helps with congestion management. Schedules submitted to the NLS must (a) be from DNRs to designated network loads, (b) be from resources and load within the same control area, (c) use registered settlement locations and (d) involve assets belonging to the same market participant.90 Currently it is anticipated that native load schedules could be modified during the operating hour (e.g., if it is 9:15 a.m. the NLS could be adjusted through 9:59 a.m.).

The Market Flow Calculator is used to provide the IDC with the flow of MW from the EIS market and network load that affects specific flowgates. If there is congestion, the NERC IDC will tell SPP to adjust on those flowgates from the EIS market. SPP then has the CAT to determine how many megawatts should be curtailed

89 See SPP EIS Market Training 2005 Operating/Reliability Gap Training on September 27, 2005 at p. 60. 90 See Native Load Scheduling Business Functions at

http://www.spp.org/TrainingToolKits/Courses/Scheduling/SchedulingNLToolKitHome.cfm.

Power Flow

e-tag bilateral contact

SPP Market Control Area A Unit 1

(Offered/ Scheduled)

Control Area C

Unit 2 (Offered/ No Schedule No

Tag)

Control Area B Load

NERC does not know Unit 2 is providing power without Market Flow Calculator and additional data. CAT would curtail Unit 2 if needed.


and from what sources. Alternatively SPP could redispatch the EIS market as appropriate.

2. Areas of Concern

There are five possible areas of concern related to this significant change in

congestion management. First, the new computer tools are complex in-and-of-themselves and complexity is

increased because they must all work together. Whether this integrated set of tools work will be determined through integration testing prior to market start.

Second, how these tools work – who is curtailed when – will only be known for

sure after experience in actual market operation. It is only then that the IMM could judge whether all market participants are treated comparably.

Third, new SPP business practices must be judged for comparability. For

example, with the better granularity, SPP will assess generators in groups (in “zones”). This can be a step forward; if one set of generators has a greater effect on a flowgate than others, these generators should be in their own zone. The concern is whether all generators are treated comparably based solely on their measured flowgate impact.

Fourth, EIS transactions will be assigned a transmission priority which will

determine whether and when they are curtailed. These transactions will be assigned to three priorities or “buckets”: (a) Priority 7/Firm Network; (b) Priority 6/Non-firm Network; and (c) Priority 2/Non-firm Hourly. The assignment was dictated by the Joint Operating Agreement (JOA) between SPP and the Midwest ISO. The JOA covers the assignment for shared (coordinated) flowgates. The Market Protocols dictates the assignment for other flowgates. It is important that these two methods of assigning transmission priority mesh.91

Fifth, there is the issue of when do the transmission customers arrange and pay for

additional transmission service in the EIS Market? In order for a customer to move energy under the Energy Imbalance Market, the customer must have purchased either SPP network service or enough SPP firm point-to-point transmission service to cover its delivery from the Energy Imbalance Market as a redirect. If not, the customer would be billed for additional transmission service to deliver energy it received from the Energy Imbalance Market. We understand this is unsettled and will be addressed further.

For example, SPP’s OATT allows a firm point-to-point customer to change its point of receipt (POR) and/or point of delivery (POD) on a non-firm basis without necessarily incurring an additional charge for non-firm point-to-point transmission

91 A specific concern is that the JOA uses the concept of a Firm-Generator-to-Load Limit forecast to

determine the market flows which are assigned Priority 7. See Joint Operating Agreement between the Midwest Independent Transmission System Operator, Inc. and Southwest Power Pool, Inc. effective December 1, 2004 at Section 5 Market-Based Operating Entity Congestion Management at p. 81.


service.92 Note that secondary service does have its limitations; secondary service will have a lower priority than all other firm and non-firm service.93 The question is whether the use of secondary service will mean no additional charge is incurred for EIS purchases and sales. Also it is unclear from the OATT and Business Practices if the capacity available on the firm point-to-point transmission service path initially reserved will become available on a non-firm basis to transmission customers.

92 See SPP OATT at section 22.1 at pp. 63-4 and Southwest Power Pool, Inc. Open Access Transmission

Tariff Business Practices April 14, 2005 Revision (“SPP Business Practices”) at section 3.1. 93 See SPP Business Practices at section 3.1.


IV. EXPANDING THE TRANSMISSION SYSTEM

A. How Are Investments to Expand the System Identified and Funded? In most areas of the country, it is generally agreed that new investment is needed in transmission systems. That investment has been stalled in part, by the failure to address two central questions: which investments should be made? and who pays? The SPP Regional State Committee (RSC), working with SPP Staff and working through the SPP stakeholder process, has made substantial progress in this regard. The RSC has split the issue into consideration of reliability upgrades and economic upgrades.

1. Reliability Upgrades The most basic responsibility of the electrical industry is to keep a steady and reliable flow of electricity to its customers. Indeed, this goal is reflected in SPP’s motto, “Helping Our Members Work Together To Keep the Lights On…Today and in the Future!”94 To provide a reliable system, reliability-related transmission investment is needed. It is often stated that regulatory and other uncertainties, as well as inefficient policies, have hindered this investment.95 As a result, in its Order Granting RTO Status Subject to Fulfillment of Requirements to SPP, FERC directed the RSC to help determine the funding and planning of regional reliability upgrades.96 In a February 28, 2005 filing before FERC, SPP presented its proposed cost allocation plan that set forth policies determining which parties would be responsible for paying for reliability upgrades.97 FERC accepted the cost allocation plan and commended the proposal as benefiting “customers by establishing cost allocation and cost recovery methods for the SPP regional transmission organization (RTO) expansion process, thereby supporting needed and efficient transmission investment and expanding wholesale power markets.”98 The basic precept of the cost allocation plan, which is also called the base plan and includes upgrades associated with certain DNRs, is that one-third of the cost of reliability upgrades will be allocated to the SPP region and be included in the base plan

94 See www.spp.org. 95 See Direct Testimony of Mark Rossi on Behalf of Southwest Power Pool, Inc. in FERC Docket No.

ER05-652-000 on February 28, 2005 (“Rossi Testimony”) at p. 15 and Direct Testimony of Bruce Rew on Behalf of Southwest Power Pool, Inc. in FERC Docket No. ER05-652-000 on February 28, 2005 at p. 4.

96 See Order Granting RTO Status at pp. 69-70. 97 See Filing of Transmission Cost Allocation Tariff Revisions in FERC Docket No. ER05-652-000 on

February 28, 2005. 98 See Order on Proposed Tariff Revisions in FERC Docket No. ER05-652-000, et. al, on April 22, 2005

(“April 22 Order”) at p. 1.

KEY POINTS IN

TRANSMISSION EXPANSION 1. Reliability upgrades help keep

the lights on

2. Economic upgrades help customers get cheaper power

3. Increased transmission can help mitigate market power concerns

4. Need to finalize policy on all aspects and develop clear, concise guidelines.


region-wide annual transmission revenue requirement to be recovered by the base plan region-wide charge. The remaining two-thirds of the cost will be allocated locally to the zones affected by the upgrade, as determined by a Megawatt-mile (MW-mile) analysis, and included in the base plan zonal annual transmission revenue requirement to be recovered through each zone’s base plan zonal charge.99 The zonal charge will likely be split among multiple zones, as each zone receiving more than 10 MW-miles of benefit, as determined by SPP’s MW-mile analysis, will be allocated a portion of the zonal charge.100 This allocation was supported by the results of a MW-mile analysis that showed that approximately one-third of the upgrades benefited the entire SPP region, which makes it reasonable that the entire region pay one-third of the cost.101 This innovative policy provides clear guidance on the issue of which parties pay for the reliability upgrades deemed necessary by SPP.

a. Identification of Reliability Upgrades through the Regional Expansion Planning Process

With a clear-cut cost allocation plan for reliability upgrades in place, an equally important step to the upgrade process is the fair and efficient identification of upgrades to be constructed. SPP has already completed its first regional expansion planning process.102 This process identified $552 million of needed reliability upgrades in part on 634 miles of new transmission lines and 646 miles of rebuilt or upgraded transmission lines, all eligible for funding under the cost allocation plan.103 SPP began by developing a transmission model and testing it to see if the modeled transmission system performs as required under various circumstances.104 The requirements for these tests are slightly different in the guidelines established by the transmission owners, SPP, and NERC (with SPP being obligated to adhere to the most stringent).105 However, these requirements generally adhere to NERC requirements.106 Generally, reliability upgrades are the transmission upgrades required to correct for the identified violations of NERC guidelines.107 Briefly, the NERC Reliability Standards analyzes the transmission system under four scenarios also know as Categories A, B, C, and D. Under each of those scenarios a

99 See SPP OATT, Attachment J at pp. 163-163A. Note that if the cost of the upgrade is less than

$100,000 it is allocated entirely to the zone in which the upgrade is located. 100 Ibid at p. 163A. 101 See April 22 Order at p. 9. 102 See SPP RTO Expansion Plan 2005-2010 Prepared by SPP Staff, SPP Engineering Planning, As

Approved by TWG: September 14, 2005. (“SPP Expansion Plan-Final”) Note that this report was not approved for submission to the SPP Board of Directors at the meeting of the SPP Markets & Operations Policy Committee on October 11-12, 2005.

103 See SPP RTO Expansion Plan 2005-2010 Phase 1 Report; Reliability Assessment, March 2005 (“SPP Expansion Plan”) at p. 8. Note that the cited monetary value of transmission upgrades includes facilities other than transmission lines.

104 See SPP Criteria at section 3.4.1. 105 See SPP Expansion Plan at p. 7. 106 See SPP Criteria at section 3.3.1. 107 See SPP Expansion Plan at p. 31.


power flow model is used to test if there are no violations in one or more of the following three conditions: (i) system stable and both thermal and voltage limits within applicable rating, (ii) no loss of demand or curtailed firm transfers, or (iii) no cascading outages. The Category A standard requires the modeling of the transmission system as it functions normally, without any transmission element outages. The Category B standard requires modeling the transmission system when it is suffering from the outage of a single transmission element. The Category C & D Standards require analysis of the transmission system with outages of two or more transmission elements, though rare, may result in severe system disturbances, including cascading outages.108 SPP conducts these tests using at least the most severe contingencies known to SPP or the transmission owners.109 All Category A & B violations identified require reliability upgrades while Category C & D violations may not result in upgrades due to the low probability of their occurrence or the existence of an operating procedure that mitigates the violation.110 The results of the transmission modeling and the discovered violations were presented at the Planning Summit II, held in Dallas, Texas in June 2004.111 SPP independently evaluated projects originating as stakeholders’ input, transmission owners’ proposed and exploratory projects, and SPP Staff’s alternative solutions, and SPP then recommended the expansion projects needed to correct the violations.112 Between March 23, 2005 and April 27, 2005 the recommendations for reliability upgrades were approved by the Transmission Working Group, the Market and Operations Policy Committee, and the Board of Directors.113 The Board of Director’s approval of the expansion plan directs the appropriate transmission owners to begin implementation of the upgrades while receiving the appropriate reimbursement under the cost allocation plan.114

2. Economic Upgrades Competition that benefits electricity consumers demands a transmission system that will allow market participants to utilize the most economic generation. Although substantial economic benefit can result from these transactions, the regional transmission system existing today is a remnant of traditional transmission planning designed to deliver electricity from DNRs to native load within individual control areas and, as such, may be inadequate to exploit these economic benefits due to transmission congestion.115

108 See NERC Reliability Standards TPL-001-0, Effective April 1, 2005 at Table 1, pp. 4-5. 109 See SPP Expansion Plan at p. 7. 110 See SPP Expansion Plan at pp. 9 and 31. 111 See SPP Expansion Plan at p. 31 and at http://www.spp.org/Doc_Results.asp?Group_id=410. 112 See Presentation by Bob Lux at SPP Regional Planning Summit II “Reliability Study Criteria &

Results” at p. 54 at http://www.spp.org/Doc_Results.asp?Group_id=410. 113 See Presentation by Bob Lux at SPP Regional Planning Summit IV “Phase 1 Reliability Plan” at p. 11

at http://www.spp.org/Publications/Summit_IV_Reliability_Plan.pdf. 114 See SPP OATT, Attachment O at pp. 185-6. 115 See SPP Expansion Plan-Final at p. 37.


Therefore, regional benefit can be realized by integrating the different control areas by constructing new transmission facilities, which creates a more cohesive regional transmission system. Transmission investments that are intended to allow this delivery of economic generation have been designated economic upgrades in SPP. Whereas reliability upgrades are equivalent to updating the system to provide the minimum amount of transmission needed to maintain deliverability, economic upgrades are elective and constructed in order to capture the economic benefit realized by reducing congestion.116

a. Proposal for Funding By defining the distinction between reliability and economic upgrades, which can be a difficult task because any transmission upgrade satisfies each category to a degree, SPP was able to create separate cost allocation procedures for the two types. As mentioned previously, FERC delegated the primary responsibility for a number of aspects of regional planning to the RSC, including the determination of the amount of participant funding to be used for transmission upgrades. The result was a proposal under which economic upgrades would be voluntarily constructed (participant funded) by project sponsors who see them as good investments.117 Preliminary efforts to define the rights of the investors in economic upgrades resulted in Attachment Z to the SPP OATT. As mentioned, the proposal did not specify mandatory funding because

These are elective facilities as they will not be built to satisfy reliability requirements. It makes sense, therefore, to require that there be project sponsors before the project moves ahead. Presumably if the project has real economic benefits, those that would benefit would agree to pay to have it constructed. Having said that, the proposal here does provide the sponsors with compensations such as credits.118

Project sponsors are responsible for the funding of an economic upgrade. The

credits mentioned in Attachment Z are transmission revenue credits for project sponsors who, as a result of the upgrade costs, pay more for transmission service than they would have, had the transmission service been available absent the upgrade. The source of the revenue for these credits comes from new transmission service using the facility.119 To

116 See SPP OATT at section 1.10a at p. 8 and SPP Expansion Plan-Final at p. 37. 117 See April 22 Order at pp. 3-4, 10, and 18. Included in this proposal was an allowance for third-party

investment and participation in economic upgrades. 118 See Rossi Testimony at p. 20. 119 See SPP OATT, Attachment Z at pp. 423 and 423B.


the extent that an economic upgrade defers or displaces the need for base plan upgrades, the economic upgrade receives the base plan allocation.120

Because the policy for economic upgrades is still being debated by the RSC, the proposal existing in Attachment Z for providing incentive to Project Sponsors may not be final. Recently, the RSC, through the Cost Allocation Working Group (CAWG), has addressed concerns that the current Attachment Z provisions do not provide sufficient incentive for participants to sponsor projects because the cost recovery mechanism only allows for the recovery of the cost of the project along with interest. As a result, the CAWG is evaluating a proposal that would allow the project sponsor to have priority use of the new transmission capacity resulting from economic upgrades as well as receive transmission revenue credits, which may provide sufficient incentive and result in substantial investment in economic upgrades.121 Also, in Attachment AA to its OATT, SPP adopted an innovative, experimental measure to allow active market participants to prepay for transmission service, thereby funding “minor economic upgrades” that accommodate, on a small scale, the non-firm short term transmission service discussed.122

b. Identification of Economic Upgrades SPP made economic upgrades the focus of the second phase of its two-year Regional Expansion Planning Process.123 The goal of this phase was to identify three or four of the most beneficial projects from a list of projects that included projects (a) not used in Phase I, (b) suggested by stakeholders, (c) mentioned at SPP planning summits, (d) identified from historical occurrence of TLR, and (e) identified from review of rejected transmission service. SPP ranked the projects and recommended the top few for evaluation as determined by the ratio of future dispatch savings over the estimated upgrade cost.124 The evaluation of these projects was made public with the publishing of the final “SPP RTO Expansion Plan 2005-2010.”125 Assuming a project sponsor finds the benefits of the upgrade and the crediting mechanism sufficient, the economic upgrade will be constructed. Project sponsors are also able to construct economic upgrades not originating in the SPP regional expansion planning process and instead are the result of their own studies.126 Presumably, a large part of the incentive to construct self-identified economic upgrades would be the benefit of resulting use, but project sponsors would also receive transmission revenue credits in accordance with Attachment Z. SPP has oversight

120 See April 22 Order at p. 4. 121 See CAWG Presentation “Participant Funding for Economic Upgrades” on August 10, 2005. (“CAWG

Presentation”) 122 See Southwest Power Pool, Inc. in FERC Docket No. ER04-833-000 on August 6, 2004 at pp. 1-5 and

Order Accepting Tariff Filing in FERC Docket No. ER04-833-000 on October 5, 2004 at pp. 8. 123 See SPP Expansion Plan at p. 97. 124 Ibid at p. 97. 125 See SPP Expansion Plan-Final. 126 See April 22 Order at p. 4.


responsibility over these projects to ensure that they will enhance, not detract from, SPP’s ability to operate the transmission system reliably and efficiently.127

3. Areas of Concern An area of concern is with the unsettled issues around the mechanisms through which economic upgrades are identified and paid for. These same issues exist for upgrades called “requested upgrades,” which are, in part, upgrades identified in the aggregate study process for transmission service.128 This lack of clarity was highlighted recently by a transmission request and request for upgrade made by a market participant. The participant inquired if it could sponsor an upgrade to be included in the aggregate study without actually taking long-term transmission service. Because the answer was not readily apparent from the language existing in SPP’s OATT and accompanying attachments, the overriding concern is that the prevailing uncertainty may have prevented the upgrade from being constructed despite the existence of a willing sponsor.129 Efforts are being made currently in several stakeholder groups to provide the clarity which will facilitate the construction of economic and requested upgrades. Going forward, we will keep abreast of this issue to help ensure that the appropriate incentives are in place to develop new transmission.

B. The RSC’s View on the Importance of Upgrades to Congestion Management

In any RTO one of the participants’ primary concerns is managing congestion costs that are often significant and volatile.130 Several RTOs have installed a system of financial transmission rights (FTRs) that allow market participants to hedge against congestion costs.131 SPP, however, utilizes physical transmission rights (PTRs) which allows participants to mitigate potential congestion costs by scheduling short term transactions and with the deliverability requirements of NITS.132 According to the RSC, transmission upgrades are essential to this system, which allow SPP to accommodate the service requests required for scheduling and ensure the deliverability of DNRs.133 As we understand it, the RSC sees the PTRs of the SPP system functioning as follows to reduce the congestion costs faced by market participants.134 By attaining NITS 127 See Order Granting RTO Status at p. 61. 128 See SPP OATT, Attachment Z at pp. 419-22. 129 See CAWG Presentation by Mike Proctor “Transmission Upgrade Request With and Without

Transmission Service Requests,” on September 27, 2005 at p. 5. 130 See Notice Inviting Comments on Establishing Long Term Transmission Rights in Markets with

Locational Prices in FERC Docket No. AD05-7-000 (“FERC Staff Paper”) at p. 1. 131 Ibid at p. 3. 132 See Southwest Power Pool Regional State Committee Comments on Establishing Long Term

Transmission Rights in Markets with Locational Pricing in FERC Docket No. AD05-7-000 (“RSC Comments”) at p. 2. Note that the RSC uses the term “scheduling” rights to describe SPP’s system of transmission rights, which encompasses the general term physical transmission rights used in this assessment. See RSC Comments at p. 6.

133 See RSC Comments at p. 2. 134 Ibid at p. 1.


for its load obligations, a Load Serving Entity (“LSE”) is essentially buying the physical transmission service from its DNRs to its load. Because SPP is responsible for maintaining this deliverability, notes the RSC, the highest cost an LSE with NITS should face to serve its load will be the cost of “operating its DNRs.”135 Using the cost certainty of a DNR as a hedge, an LSE can pursue economic short-term bilateral transactions. However, these short-term transactions will themselves only be effective if the LSE can obtain short-term transmission service.136

1. The Importance of Base Plan Upgrades The type of facility upgrades included in the base plan are those required for reliability, which are important to maintain the functionality of the transmission system, and DNRs, which are necessary to allow the hedging of congestion costs. This is critical to SPP’s scheduling rights for several reasons. The overall purpose “is to use investment in transmission infrastructure to reduce overall market risk when it is cost beneficial to do so.”137 First, SPP is obligated to maintain the deliverability of DNRs. This may require significant transmission upgrades as (a) the transmission system ages and (b) load flow patterns change with the addition of new load and generation to the RTO. The inclusion of DNR-related upgrades to the approved cost allocation plan provides a clear source of funding for upgrades once identified.138 The RSC comments that this sends a strong signal to potential investors in generation that SPP will be able to provide transmission service to serve load from proposed generation.139 According to the FERC Staff Paper on Long Term Financial Transmission Rights, one of the historical complaints with PTRs is that access to the transmission system is provided on a discriminatory basis.140 However, the SPP base plan uses objective criteria to determine a generators’ eligibility for DNR status, which levels the playing field by helping to ensure equal access to DNR status for all transmission customers. Briefly, these criteria are:

• The transmission customer commits to the DNR for at least 5 years, • The total of the transmission customer’s existing DNR capacity and the

requested DNR is less than 125% of its peak load, and • The upgrades cost less than $180,000/MW of the requested capacity.141

Respectively, the criteria also prevent regional funding for upgrades (a) unimportant for the future, (b) to be used for off-system sales, and (c) uneconomically located, which

135 See RSC Comments at p. 3. 136 Ibid at p. 4. 137 Ibid at p. 4. 138 Ibid at p. 4. 139 Ibid at p. 4. 140 See FERC Staff Paper at p. 6. 141 See SPP OATT, Attachment J at p. 163B.


helps assure that the transmission investment is cost beneficial.142 Because “any plan must have sufficient flexibility built in to it so that it is both practical and does not create any undesirable barriers to the competitive marketplace,” transmission customers can request a waiver if its project fails the criteria.143 The waiver request will be viewed by various SPP organizational and stakeholder groups which will evaluate the benefits of the proposal.144

2. The Role of Economic Upgrades With PTRs, the complement of the deliverability assurance of DNRs is the ability to schedule short-term energy transactions. Market participants can use their long-term, set-price DNRs to hedge opportunistic, short-term and economically beneficial bilateral contracts. Also important for reasons such as keeping prices at a reasonable level during times when DNRs are undergoing maintenance, the short term transactions must also be protected from congestion costs by hedging them with short term transmission service.145 “If the RTO wants to have a strong market for bilateral transactions in addition to the spot markets that it facilitates, it must consider how to provide hedging for congestion costs associated with these shorter-term transactions.”146 However, transmission service is not always available to hedge the short-term transactions due to “residual” congestion costs. This “residual” congestion occurs when the demand for redirected NITS and short term point-to-point service exceeds capacity.147 Transmission investments intended to reduce this “residual” congestion are the type that qualify as economic upgrades. The economic benefit of being able to replace expensive energy with less expensive energy is not realized due to transmission congestion. Because of the importance of having them built, favorable incentive conditions may be required to spur such efficiency-enhancing investment in economic upgrades.148 Finalizing a proposal for the funding of economic upgrades will be an important contribution by the RSC which will facilitate transmission investment in SPP.

C. How Are New Power Plants Interconnected to the Transmission System?

Interconnection policies detail the procedures new generators must follow in order to connect to the transmission grid. Ideally, interconnection policies facilitate new entry and promote competition. To this end, interconnection policies should be fair, consistent, and not unduly burdensome. In Order No. 2003, FERC concluded that standardization was needed to ensure competition among generation resources in the wholesale electricity market and to help prevent undue discrimination, and pursuant to the Order, SPP has included in its OATT a pro forma Large Generator Interconnection Procedures

142 See Rossi Testimony at pp. 10-12. 143 Ibid at p. 12. 144 See SPP OATT, Attachment J at pp. 163C-E. 145 See RSC Comments at pp. 2-3. 146 Ibid at pp. 4-5. 147 See CAWG Presentation at pp. 2-4. 148 Ibid at p. 8.


(LGIP) and a pro forma Large Generator Interconnection Agreement (LGIA). 149 If a merchant plant or a utility plant wants to begin operation in SPP, or an existing plant wishes to increase its capacity, it must go through the generation interconnection process. This process begins with the submission of an interconnection request by the interconnection customer and progresses from there through a series of major studies and agreements: (i) a Feasibility Study, (ii) a System Impact Study, (iii) a Facilities Study, and (iv) a LGIA.150 Throughout this process, the interconnection customer agrees to reimburse SPP or the transmission owners for the cost of the studies and reimburse SPP or the transmission owners for any necessary attachment facilities and transmission upgrades associated with interconnection request. 151 According to the LGIP, SPP or the transmission provider has the option of prioritizing the generation interconnection requests on a first-come, first-served basis, based upon the date of the request or clustering (aggregating) the request over an open period to be studied jointly.152

1. Interconnection Request

The first step in the generation interconnection process is the submission of an interconnection request to SPP. Included in this request will be:

• A $10,000 deposit • Evidence that the interconnection customer owns or has control over the

generating unit or an additional $10,000 deposit; • The capacity of the unit (or capacity increase)153 • A complete application form, which includes (i) the type of

interconnection service requested [Network Resource Interconnection Service or Energy Resource Interconnection Service],154 (ii) the location of the generating unit, (iii) general descriptions of physical equipment configuration, and (iv) the proposed operation.155

SPP will acknowledge receipt of the interconnection request within five business days and notify the participant of any deficiencies. Within thirty days after receiving a valid interconnection request, SPP and the interconnection customer shall hold a scoping meeting to discuss alternative interconnection options, exchange information regarding 149 See Standardization of Generator Interconnection Agreements and Procedures, Order No. 2003 in

FERC Docket No. RM02-1-000 issued July 24, 2003. 150 See SPP OATT, Attachment V at p. 265. 151 Ibid at p. 296. This process is for capacity increases greater than 20 MW. 152 Ibid at p. 275. 153 Ibid at pp. 271-2. 154 Ibid at p. 269. 155 Ibid at pp. 300-5.

STEPS IN SPP

INTERCONNECTION POLICY

1. Initiate Request 2. Follow Interconnection Feasibility

Study Procedure 3. Follow Interconnection System Impact

Study Procedure 4. Follow Interconnection Facilities Study

Procedure 5. Execute LGIA 6. Build Facilities


the facility design and transmission system, determine potential points of interconnection. At the same time a customer submits an interconnection request, it must also submit a completed Interconnection Feasibility Study Agreement.

2. Interconnection Feasibility Study Procedure Concurrent with the acknowledgement of a valid interconnection request, SPP provides the interconnection customer with an Interconnection Feasibility Study Agreement which specifies that the customer is responsible for the actual cost of the study. Within five days following the scoping meeting, the customer must provide SPP with the point of interconnection (along with reasonable alternatives). Five days thereafter, SPP will provide the customer with an Interconnection Feasibility Study Agreement and a good faith estimate of the cost of the study. The customer must then execute and return the agreement along with a non-refundable deposit of $10,000 towards the costs of this study within thirty days.156 The study includes a power flow and short circuit analysis. The purpose of the study is to provide a non-binding, good faith estimate of (i) the kind of facilities and upgrades that will be needed to accommodate the interconnection request, (ii) the time it will take to construct such facilities, and (iii) the cost responsibility of the customer for such facilities.157

3. Interconnection System Impact Study Procedure The next step in the interconnection process is the System Impact Study. This study identifies the system constraints associated with the interconnection request and the attachment facilities and upgrades that will be necessary to accommodate the request. It also provides a more comprehensive estimate for the customer’s cost responsibility than did the Feasibility Study.158 SPP gives the interconnection customer an Interconnection System Impact Study Agreement when the Interconnection Feasibility Study is completed. After it receives the agreement, the customer has 30 days to do the following or risk having its interconnection request terminated:

• Sign and return the Interconnection System Impact StudyAgreement • Pay SPP a $50,000 deposit towards study costs • Provide technical data.159

The study will include a short circuit analysis, a stability analysis and a power

flow analysis. This study will provide a list of the facilities that are required as a result of

156 See SPP OATT, Attachment V at p. 279. 157 Ibid at p. 281. 158 Ibid at p. 281. 159 Ibid at pp. 281-2.


the interconnection request, a non-binding, good faith estimate of (i) the time it will take to construct such facilities, and (ii) the cost responsibility of the customer for such facilities.160

SPP will use reasonable efforts to deliver a completed study within 90 days after

the close of the queue cluster window.

4. Interconnection Facilities Study Procedure The next step in the interconnection process is the Interconnection Facilities Study. This final study will specify and estimate the cost of equipment, engineering, procurement and construction needed to connect the generation with the transmission system. Included in the study will be an estimate of network upgrades as well as an estimate of the time required to complete construction.

Upon completion of the Interconnection System Impact Study, the interconnection customer is given a Facilities Study Agreement by SPP. Under this agreement, the customer agrees to pay for the cost of the study, and SPP in turn gives the customer an estimate of the cost of the study and the time it will take to complete it. Within thirty days, the customer must execute the agreement and provide SPP a deposit equal to the greater of $100,000 or the estimated amount of the study cost.161

5. Standard Large Generator Interconnection Agreement When all the studies have been completed, the customer enters into an LGIA with SPP.162 This is the final phase of the interconnection process. During this phase the transmission provider and the interconnection customer can spend up to sixty days negotiating.

The interconnection customer must, within fifteen (15) days after receipt of the signed LGIA, provide a non-refundable $250,000 security deposit to be applied toward future construction costs or evidence that it controls the generation site. In addition the customer must provide evidence that one or more milestones have been made:

• Entered into any necessary fuel supply or cooling water agreements; • Executed contracts for the engineering for, procurement of major

equipment for, or construction of, the Large Generating Facility; • Entered into a power purchase agreement; or • Applied for the necessary air, water, or land use permits.163

6. Cost Responsibility

160 See SPP OATT, Attachment V at pp. 282-3. 161 Ibid at p. 284. 162 Note that there are additional optional studies that could be performed at the customer’s request. 163 See SPP OATT, Attachment V at pp. 288-9.


The interconnection customer is responsible for bearing the cost of all interconnection facilities, the facilities need to physically attach the generating unit to a transmission provider’s system, that are necessary to accommodate its interconnection request. The interconnection customer also pays for transmission system upgrades that have to be made to accommodate the interconnection request and is eligible for reimbursement for those upgrades over 20 years.164

7. Areas of Concern

FERC Order 2003 is designed to standardize the generator interconnection request process, therefore, it in-and-of-itself is a good mitigation for transmission market power abuse. However, under the LGIP in SPP’s OATT it appears the transmission owner could be the one performing all of these studies or at least providing input into the studies.165 For example, Southwestern Power Administration’s website states that it is the entity to be contacted for interconnection requests.166 Westar’s website indicates that SPP will be the one handling the requests.167 Again, going forward, we hope that a set of checks and balances are developed to ensure equitable treatment among all parties interconnecting. \\Powervault\filecabinet\Active Projects\SPP\SPP MMP\Initial Assessment\Working Drafts\Working_Draft_10_14_05.doc

164 See SPP OATT, Attachment V at pp. 372-3A. 165 See SPP OATT, Attachment V at p. 268. 166 See “Interconnection Requests” at Southwestern Power Administration,

http://www.swpa.gov/interconnection.htm 167 See “Westar Energy Oasis” at http://sppoasis.spp.org/OASIS/WR


Attachment One

DESCRIPTION OF SPP MEMBERS AND ROLES

OATT Zone

SPP Control

AreaSPP

OASISRTO

MemberSPP

OATT?Transmission Dependent

Investor OwnedAmerican Electric Power 1 Y Y Y PartialAquila, Inc. Missouri Public Service 9 Y Y Y Partial West Plains Energy 15 Y Y Y PartialCleco Power LLC 2 Y YEntergy Services, Inc. Y YExelon Power Team YKansas City Power & Light (KCPL) 6 Y Y Y PartialOG&E Electric Services (OGE) 7 Y Y Y PartialSouthwestern Public Service (SPS) 11 Y Y YEmpire District Electric (EDE) 4 Y Y Y PartialWestar Energy, Inc. 14 Y Y Y Y

CooperativesArk. Electric Coop Y YEast Texas Elec. Coop Y YKansas Electric Power Cooperative YMidwest Energy 8 Y Y YNortheast Texas Elec. Coop Y YSunflower Electric 12 Y Y Y YTex-La Coop. Y YWestern Farmers Elec. Coop 13 Y Y Y Y

MunicipalsCity of Clarksdale, MS Y YCity of Lafayette, LA (LAFA) Y Y YCity Power & Light, Independence, MO (INDN) Y Y YCity Utilities, Springfield, Mo 3 Y YOklahoma Municipal Power Authority YPublic Service Comm. of Yazoo City, MS Y YBoard of Public Utilities, KA (KACY) Y Y Y

State AgenciesGrand River Dam Authority (GRDA) 5 Y Y Y PartialLouisiana Energy & Power (LEPA) Y Y

Independent Power ProducerCalpine Energy Services, L.P. Y YRedbud Energy, L.P. Y YTenaska Power Service Company Y Y

MarketersAquila Power Y YCargill Power Markets, LLC Y YCinergy Corp. Y YConstellation Energy Commodities Group, Inc. Y YCoral Power, LLC Y YDynegy Marketing & Trade Y YDuke Energy Trading & Marketing Y YEdison Mission Marketing & Trading, Inc. Y YEl Paso Merchant Energy, L.P. Y YNRG Power Marketing, Inc. Y YTXU Energy Trading Company YWilliams Power Company, Inc. Y Y

Customers other than MembersSouthwestern Power Admininstration 10 Y Y Y

Entity


Attachment Two

TIMING OF RESERVATIONS AND SCHEDULING

Service Type

Term SPP

Response

Determine Capacity Available

Complete System Impact

Study

Customer Response 1/

No Later Than

No Earlier Than

No Later Than (Prior )

No Earlier Than (Prior to)

LT Firm > = 1 Year 60 days 15 days 30 days 60 days 15 days 1200 day 20 min. (hr)ST Firm (mnthly) > 1 mnth 31 days 120 days 24 hrs 30 days 60 days 4 days 1200 day 20 min. (hr)ST Firm 1 mnth 8 days 90 days 24 hrs 30 days 60 days 4 days 1200 day 20 min. (hr)ST Firm (wkly)

> 1 wk up to 1 mnth 8 days 60 days 24 hrs 30 days 60 days 48 hrs 1200 day 20 min. (hr)

ST Firm 1 wk 2 days 30 days 24 hrs 30 days 60 days 48 hrs 1200 day 20 min. (hr)ST Firm (Daily)

> 1 day up to 1 wk 2 days 14 days 24 hrs 30 days 60 days 24 hrs 1200 day 20 min. (hr)

Queued > 24 hrs to start: 30 days

> 24 hrs to start: 24 hrs 1200 day 20 min. (hr)

Queued < 24 hrs to start: best effort

< 24 hrs to start: 2 hrs

Non-Firm (mnthly)

1 mnth or > (monthly) 3 days 60 days N/A 2 days N/A 24 hrs 1500 day 20 min. (hr)

Non-Firm (wkly)

1 wk up to 1 mnth 2 days 14 days N/A 4 hrs N/A 24 hrs 1500 day 20 min. (hr)

Non-Firm (daily)

1 day up to 1 wk 1,200 days 2 days 4/ N/A 30 mins N/A 2 hrs 1500 day 20 min. (hr)

Queued > 1 hr prior to start: 30

min. Queued day

prior: 30 mins 20 min. (hr) 20 min. (hr)

< 1 hr: Best Effort Current day: 5

min 5/

Next Hour Next-hour 20 mins 3/ 1 hour 3/ N/A Best Effort N/A N/A 3/ 20 min. (hr) 3/ 20 mins (hr)3/

2/ The Transmission Provider, in its discretion exercised on a non-discriminatory basis, may waive any of these requirements. 3/ All Next-Hour Market requests are submitted on schedule request and are deemed to be pre-confirmed.4/ Excluding Sundays and NERC Holidays. 5/ Or 2300 of previous day if for first hour of day.

1/ For transactions not covered by an umbrella service agreement, the customer response must be execution of a service agreement or a request that an unexecuted service agreement be filed with the Commission pursuant to Section 15.3 of the Tariff. For transactions under an umbrella service agreement, the above times are the deadlines by which time the customer must notify The Transmission Provider of its acceptance of the offer to provide transmission.

6/ Non-firm schedules will be accepted after 1500 day prior if there are no new reliability risks identified since the reservation was accepted. This includes but is not limited to NERC TLR in effect.

7/ With regard to non-firm hourly for next day transmission involving the DC ties under the SPP OATT, the following rule applies to limit abuse of SPP’s scheduling process: If more than ten (10) requests are submitted by the same Transmission Customer or group of affiliated Transmission Customers per DC tie, per direction between 11:55:00 a.m. and 12:05:00 p.m. CPT, then all such requests shall be considered invalid.

N/A Non-Firm (hrly)

1 hour up to 1 day 30 mins 1,200 day N/A

From Date of Customer Commitment

Energy Scheduling 2/

60 days ST Firm 1 Day

Transmission Requests

1,000 days 3 days 4/ 24 hrs

Southwest Power Pool FINANCE COMMITTEE

Recommendation to the Board of Directors October 25, 2005

Roster: Harry Skilton, Chair Director Larry Altenbaumer Director Gary Voigt Arkansas Electric Coop Corp Trudy Harper Tenaska Doug Henry Westar Energy Michael Desselle AEP

Background The Finance Committee met on October 11, 2005 to review SPP’s proposed budget for 2006. SPP’s 2006 proposed budget includes expenditures as follows:

$000 Operating Expense $52,246 Debt Service $7,023 FERC Assessments $7,200 Capital Expenditures $13,793

SPP’s 2006 budget has also been segregated to identify costs associated with on-going operations separately from costs associated with new or developing initiatives. On-going revenues and costs are presented within the Foundation budget while other costs are presented per initiative. Revenues Op. Exp Debt Serv. FERC CapEx ($MM) ($MM) ($MM) ($MM) ($MM) Foundation $52.4 $43.9 $7.0 $7.2 $3.9 EIS $0.0 9.3 0.0 0.0 2.0 Contract 9.8 4.7 0.0 0.0 0.4 New Facility 0.0 0.6 0.0 0.0 7.5 SAS70 0.0 0.8 0.0 0.0 0.0 Recommendation The Finance Committee recommends approval of the 2006 SPP budget as submitted. Approved: Finance Committee October 11, 2005 Action Requested: Approve Recommendation

2006 BUDGET EXECUTIVE SUMMARY

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INTRODUCTION/OVERVIEW SPP’s 2006 operating budget (all cash outflows excluding capital items) totals $67MM, as compared to $55MM in 2005. SPP’s 2006 capital budget totals nearly $14MM as compared to over $18MM in 2005. SPP’s administrative fee will remain at 16¢/MWh during 2006 SPP’s 2006 budget includes additional analysis versus prior years to facilitate enhanced review and tracking during the budget year. SPP’s 2006 budget is subdivided into the activities or projects:

Foundation – Foundation activities represents revenues and expenditures associated with all functions currently performed by SPP. The Foundation budget is intended to provide a transparent view into SPP’s financial management and cost control capabilities.

EIS Market – This section separates EIS Market incremental costs directly associated with the implementation of an imbalance energy market by SPP during 2006. SPP has substantial imbedded and legacy costs associated with its EIS market that are included within the Foundation budget. Examples of these costs include existing staff working strictly on EIS implementation, principal and interest costs related to the funding of capital expenditures required to develop the EIS market.

Contract Services – Contract Services activities represents a new initiative for SPP during 2006 whereby SPP will provide services under contract to members and non-members. SPP has been awarded one contract for services and expects another to be implemented during 2006.

New Facility – New Facility activities include the capital costs associated with construction of SPP’s primary operations facility and the associated systems and furnishings required to make the facility operational. Operating costs including utilities, landscape maintenance, etc are included as well.

SAS70 – SAS70 activities include all incremental costs associated with implementing an enhanced control environment within SPP. These costs are primarily personnel, however, some minor software and capital costs are also included.

SPP will carry a revenue surplus of $9.7MM into 2006. The surplus is a byproduct of the delayed implementation of EIS market originally planned for October 2005. Due to this delay, SPP has appropriately deferred budgeted expenditures (primarily staff additions and maintenance agreements) into the 2006 budget year. SPP’s 2005 administrative fee was established prior to decisions to defer market implementation and related expenditures, resulting in revenues exceeding SPP’s net revenue requirement for the year. The surplus will serve to reduce the SPP administrative fee in 2006. Absent the surplus, SPP’s 2006 administrative rate would equal 17.68¢/MWh.


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Calculation of SPP’s 2006 administrative fee is as follows: ($000) 2006 Gross Revenue Requirement $66,469 Less: Member Fees and NERC Assessment (2,042) Miscellaneous Income (Studies and Interest) (1,751) Schedule 12 Revenue (7,200) 2006 ICT Revenue (9,760) 2006 Net Revenue Requirement (“NRR”) $45,716 Divided by 2006 Estimated Billing Determinants 258,558,000 2006 Administrative Fee $0.1768/MWh 2006 NRR less 2005 surplus $35,992 2006 Adjusted Administrative Fee $0.1392/MWh EIS Market Project Budget Summary The Company’s primary operational initiative during 2006 is implementation of the energy imbalance services market (“EIS”). Currently, the EIS is scheduled to be operational effective May 1, 2006. Once fully operational, EIS will settle imbalance energy financially across the SPP footprint. Charles River & Associates, International estimate benefits from this market exceeding $370MM over a ten-year period. Budgeted operating costs expected in 2006 are $9.3MM; SPP expects to incur capital expenditures of $2MM to complete the systems required to host the EIS. The addition of nine operations staff and two IT staff are incremental personnel costs. The operations staff additions were approved at the July 2005 SPP Board of Directors meeting. SPP anticipates hiring five operations staff during 2005 and six staff (four operations and two IT) in January 2006. Total incremental staffing costs related to EIS are estimated to be $1.1MM. SPP also forecasts increased incremental costs associated with enhancing its communications network to handle the flow of data for the EIS market and upgrading the maintenance support agreements in connection with software for the EIS market systems. Incremental costs for these components are $0.4MM and $1.8MM, respectively. Finally, SPP contracts with numerous vendors to provide project management and project support during the development of the EIS market as well as on-going services once the EIS market is operational. The bulk of these expenditures are associated with a contract terminating at the end of 2006 (put into service in 2001) whereby SPP outsourced the day-to-day operation of the commercial operating system. In aggregate, vendor services are expected to total $5.9MM during the 2006 budget year.


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Expenditures ($000) 2006 Salaries & Benefits $1,062 Travel 33 Administrative 2 Meetings 78 Communications 394 Leases & Maintenance 1,840 Outside Services 5,926 TOTAL EIS MARKET $9,335 Capital Expenditures $2,043

Contract Services Project Budget Summary SPP anticipates performing services for a fee to capitalize on our core competencies. SPP will selectively respond to requests for proposals based on the potential benefits to the SPP organization and our capability to perform the functions at a level consistent with SPP’s quality standards. SPP projects providing independent coordinator of transmission services (“ICT”) beginning in the second quarter of 2006. ICT services will require headcount increase of 34 staff. A two-year contract has been negotiated for the performance of ICT services generating annual revenue of $11.9 million. ICT revenue is projected to offset $4.9 million of SPP’s imbedded infrastructure costs resulting in a net reduction of SPP’s administrative fee of nearly 1.9¢/MWh annually. Expenditures to perform contract services are primarily associated with increased staffing to manage the workload. The chart below details the expected organization requirements to satisfy SPP’s ICT obligations.

SPP is operating under an interim agreement to provide ICT services until such time as SPP is capable of delivering the services and the customer is capable of receiving the services. Under

Executive Director (6)

Planing (7) Security Operations (9) Weekly Procurement (4) Tariff Admin (8)


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the interim agreement, the customer will reimburse SPP for all incremental costs incurred in connection with provision of ICT services.

Expenditures ($000) 2006 Salaries & Benefits $4,524 Travel 140 Administrative 18 Meetings 26 Communications 72 Leases & Maintenance 42 Outside Services 24 TOTAL CONTRACT SERVICES $4,846 Capital Expenditures $401

New Facility Project Budget Summary SPP’s current operations facility lacks security, redundancy, space, and functionality to fulfill its mission. The SPP Board of Directors approved funding for the construction of a 15,000 sq.ft. primary operations facility in the amount of $3.5MM. In addition, the 2005 budget included capital expenditures to furnish the facility with computing equipment, work space, etc. in the amount of $2.5MM. SPP acquired 10.5 acres of land in May 2005 for $300K. Construction of the building has been delayed, as the building design needed several iterations to include additional operational requirements with respect to the ICT and the EIS market. The final building design is slated for presentation to the local planning commission on October 27, 2005 with construction to begin immediately following planning commission approval. The final design encompasses 20,000 sq.ft. and is sized sufficient to house some expected growth of Contract Services staff as well as some other potential operational requirements. Hard dollar construction costs are now estimated to be $3.6MM. Build-out of the facility including data center equipment and licenses, redundant electrical and HVAC systems, and workspace is now estimated to total $3.9MM. The current timeline indicates completion of the building shell and issuance of an occupancy permit in September 2006. Build-out of the systems required to make the facility operational will require another two to three months.

Expenditures ($000) 2006 Salaries & Benefits $103 Administrative 178 Leases & Maintenance 269 Outside Services 30 TOTAL NEW FACILITY $580


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Capital Expenditures ($000) Building (excl. land) $2,6101

1 Total estimated construction costs, a portion of which may be expended during the 2005 budget year.

Furnishings 975 Systems & Software 3,902 TOTAL NEW FACILITY CAPEX $7,487

SAS70 Project Budget Summary SPP, in response to the Sarbanes Oxley certification requirements of several of its members, initiated a program to both enhance the necessary controls and undergo control audits annually. SPP has worked to fully document its internal control environment and has required additional resources to enhance its controls. During 2006 SPP projects additional resource requirements to ensure segregation of duties within its technical function.

Expenditures ($000) 2006 Salaries & Benefits $103 Administrative 400 Leases & Maintenance 41 TOTAL SAS70 $544

SALARY/EMPLOYEE BENEFITS Employee costs are the single largest component of SPP’s annual operating budget comprising nearly 45% of SPP’s annual revenue requirement. Expenditures in this area have grown commensurate with approved increases in headcount and approved salary adjustments.


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2001 2002 2003 2004 20052 2006 Headcount 110 112 116 136 155 238 Total Salary ($MM) $7.0 $7.8 $9.1 $10.4 $7.8 $19.1 Salary Rate ($MM) $8.1 $8.2 $8.9 $10.4 $12.6 $19.3 SPP’s 2005 budget approved a total of 166 positions. During the year, several positions were approved for hire by the Board of Directors and by the SPP President. The approved headcount (for hire in 2005 and 2006) is 215. This budget includes requests for 21 additional staff; bringing total approved staffing to 236 employees. Below is a reconciliation of SPP’s headcount from the original 2005 budget through the 2006 budget, as well as descriptions of the proposed new positions not previously approved and a summary organizational chart Positions approved in 2005 budget 166 Positions approved mid-year by President Release Mgr – IT 1 Communications Mgr 1 2 Part-time 4 Positions approved mid-year by BOD ICT 31 Operations 14 Total approved positions 215 New positions in 2006 Administrative 4 Corporate Affairs 1 Operations 1 Engineering 1 Regulatory 1 IT 14 Eliminated positions in 2006 Part-time -1 Net 2006 Budget Headcount 236 Administration (4) Corporate Accounting

Accountant I - Grade 5 Position supports growing workload in the accounting department for controls and focus on SPP finances. This position represents conversion of an existing part time position to a full-time Accountant I.

2 Through September 30, 2005


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Accountant II - Grade 6 Position supports SPP's desire to centralize the corporate purchasing function. Centralization would create greater efficiencies company wide as current process is a decentralized, manual process, requiring a great deal of time from many people across the company.

Human Resources/Facilities

HR Generalist I – Grade 5 Position supports SPP’s initiative to place all benefits coordination under the direction of one staff member providing enhanced communication and coordination with SPP staff regarding their benefit plans in addition to allowing current SPP HR staff additional time to dedicate towards recruiting, hiring, retention, staffing, training and staff development.

Credit Credit Analyst I – Grade 5

Position supports the implementation of the new credit policy and the associated increase in the amount of analysis and documentation that will need to be maintained.

Corporate Affairs (1) Communications

Communications Specialist II – Grade 6 Position supports the growing needs of our organization for effective communication within SPP and for its stakeholders. The present workload and reactive mode do not foster a strategic or coordinated approach to communicating with our existing and prospective stakeholders. The current daily demands repeatedly exceed our staff resources and hinder attempts at strategic or proactive activities. Frequently, the response to internal customers’ requests are postponed or denied.

Engineering (1) Tariff Studies

Engineer III – Grade 8 Position supports the initiative for the Aggregate Transmission Service Study (ATSS) required to be performed under the OATT three times annually. Study requirements will increase as the complexity of the study develops. This position will be fully billable to the customers of the ATSS.

IT Applications (8) Summary

Positions support the following projects/initiatives: the Entergy ICT, the Joint Operating Agreement (JOA) with MISO, the Market Monitoring Project, the Implementation of a


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Controlled Environment at SPP, and the new functionality being added to the EIS Market systems. Specifics: 1.50 FTE Entergy ICT

[0.5 FTE IT Specialist I (Grade 6) + 1.0 FTE IT Specialist II (Grade 7)] 1.00 FTE JOA systems & Seams Agreements

[1.0 FTE IT Specialist III (Grade 8)] 2.00 FTE Implementation of Controlled Environment (Separation of Duties)

[2.0 FTEs - IT Specialist II (Grade 7)] 2.50 FTE Implementation of EIS Market (Existing + New Functionality)

[2.0 FTEs - IT Specialist II (Grade 7) + 0.5 FTE - Supervisor, EMS/Reliability Support (Grade 9)]

1.00 FTE Support Reliability Function Enhancements [0.5 FTE - Supervisor, EMS/Reliability Support (Grade 9) + 0. 5 FTE IT Specialist I (Grade 6)]

_______ 8.00 FTE

IT Infrastructure (6) Summary

Positions support the following projects/initiatives: the Entergy ICT, the Implementation of a Controls Environment at SPP, the new functionality being added to the EIS Market systems, and the addition of the New Facility. Specifics: 1.75 FTE Entergy ICT

[1.0 FTE IT Specialist II (Grade 7) + 0.5 FTE IT Specialist I (Grade 6) + 0.25 FTE Security Analyst I (Grade 6)]

1.75 FTE Implementation of Controls Environment [1.25 FTE IT Specialist II (Grade 7) + 0.25 FTE IT Specialist I (Grade 6) + 0.25 FTE Security Analyst I (Grade 6)]

0.25 FTE Implementation of EIS Market [0.25 FTE IT Specialist II (Grade 7)]

2.25 FTE New Facility [0.5 FTE IT Specialist II (Grade 7) + 1.25 FTE IT Specialist I (Grade 6) + 0.5 FTE Security Analyst I (Grade 6)]

_______ 6.00 FTE


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Operations (1) Operations Engineering

Operations Engineer I – Grade 7 Position supports the increased volume of system impact study requests for firm reservations primarily in the short-term (weekly and daily) requests. The recent filing of Attachment AC of the SPP OATT will result in increased volume of requests due to improved timing requirements and increased awareness among market participants of available re-dispatch options.

Regulatory (1) Staff Attorney – Grade 8

Position supports the following continuing and new initiatives: • Generator Interconnection • Formula Rates • EIS Market Implementation • Energy Bill • Entergy ICT

There is growing evidence that justification already exists and will continue to grow for additional legal support in SPP’s regulatory area. Legal and consultants fees for the period 1/1/05 through 7/20/05 has been $624K as compared to $363K during the same period in 2004. Additionally, the number of cases pending as of the end of the second quarter 2005 stood at 21 compared to seven at that point in 2004.

CommunicationsCurrent Employees: 3Proposed Employees: 1

TrainingCurrent Employees: 6

Customer ServiceCurrent Employees: 5

Legal & Corporate AffairsCurrent Employees: 1

Contract ServicesExecutive Directror: 1, Current Employees: 1Unfilled positions: 29

ComplianceDirector: 1Current Employees: 1

Market DevelopmentDirector: 1Current Employees: 5Unfilled positions: 3

AccountingDirector: 1; Current Employees: 9, 1 part timeUnfilled positions: 4Proposed Employees: 3

Human Resources, Facilities, AdministrationCurrent Employees: 6Proposed employees: 1

Finance

ApplicationsCurrent Employees: 24Unfilled positions: 1Proposed Employees: 8

InfrastructureCurrent Employees: 11Unfilled positions: 1Proposed Employees: 6

Telecommunications/SecurityCurrent Employees: 7Unfilled positions: 1

Change ManagementCurrent Employees: 2

Information TechnologyDirectors: 2

PlanningCurrent Employees: 6

Tariff StudiesCurrent Employees: 7Unfilled positions: 1Proposed Employees: 1

TransmissionCurrent Employees: 4Unfilled positions: 1

RegulatoryDirector: 1Current Employees: 2, 1 part timeProposed Employees: 1

Engineering & RegulatoryDirector: 1Administrative: 1

Market OperationsCurrent Employees: 7Unfilled positions: 2Proposed employees: 1

Operations EngineeringCurrent Employees: 6Unfilled positions: 3Proposed Employees: 3

EMS Applications & Network ModelsCurrent Employees: 5Unfilled positions: 1Proposed Employees: 2

SchedulingCurrent Employees: 8

ReliabilityCurrent Employees: 7Unfilled positions: 2Proposed Employees: 2

Tariff AdministrationCurrent Employees: 7

OperationsDirector: 1

ExecutiveCurrent Employees: 7

The SPP Human Resources Committee is currently reviewing the benefits of implementing a performance compensation plan beginning in 2005. The plan, as currently designed, would compensate SPP employees for their individual contribution to SPP’s overall corporate performance. Payouts under the plan are expected to equal approximately15% of year-end


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salaries. Cash outflows for performance compensation earned in 2006 would occur in February 2007. Medical healthcare insurance premium rates have been budgeted to remain flat as SPP expects to benefit from its internal wellness initiatives and increased group size. Total premiums will increase in tandem with the increase in headcount. SPP currently splits healthcare premiums with employees using an 80%/20% ratio. The HR Committee reviewed SPP’s benefit programs in 2005 and has not recommended changes to healthcare funding. Funding levels for SPP’s defined benefit retirement plan and retiree healthcare are also budgeted to remain flat. SPP obtains an actuarial report in mid May that is utilized by the HR Committee to establish the annual funding level. Funding for SPP’s matching contribution to the 401(k) plan is estimated at 4.5% of salary. Compensation of SPP’s independent directors is forecast to total $345K in 2006. SPP recently approved additional compensation for directors related to attendance at meetings where the director is not a member of the meeting group or at other required meetings. Better meeting planning has resulted in fewer board level committee meetings in 2005 versus 2004 supporting a reduced estimate for director compensation compared with the 2005 budget ($390K). EMPLOYEE TRAVEL Expenditures in this category include hotel, airfare, dining, and entertainment expenditures incurred by SPP employees in the performance of their assigned duties. SPP responsibilities related to participation and facilitation of SPP working groups and task forces, as well as NERC activities, necessitates substantial travel. 2005 actual travel expenses are projected to equal 94% of the 2005 budget. 2006 travel, exclusive of travel expenses related to ICT services, is forecast to exceed 2005’s budget by 10% as a result of additional meetings in advance of EIS implementation and higher fares resulting from recent spikes in fuel prices. SPP will remain diligent in managing travel expenditures in the most efficient manner possible. ADMINISTRATIVE Insurance includes standard insurance coverage to protect the company, its employees and directors, and the membership from unforeseen events. SPP anticipates increasing coverage limits for director & officer liability to address concerns voiced by several members of the board. We anticipate purchasing an excess layer above SPP’s existing D&O program designed to provide coverage in the event SPP is unable to fully indemnify the insureds. Below is a summary of SPP’s insurance programs and premiums: Limit ($000) Premium ($000) ’05 Premium General Liability $1,000 $42 $29 Excess Liability (E&O) $75,000 $873 $670 D&O Liability $50,000 $125 $51 Audit expenses in 2006 include $45K for the annual audit of SPP’s financial statements and an additional $400K to cover the costs associated with engaging a type-II audit of SPP’s control environment. These expenditures are in line with SPP’s experience during 2005.


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SPP has reclassified its budgeting for small equipment and software purchases to the Administrative category from the Capital Expenditures category to more properly budget in line with GAAP reporting. The 2006 budget for Administrative expenses includes $226K in these expenditures. Subscriptions include costs associated with maintaining a credit rating with Standard & Poor’s. SPP will also subscribe to a credit reporting service to facilitate ongoing review and monitoring of creditworthiness of customers of the tariff. ASSESSMENTS & FEES SPP’s NERC assessment is expected to increase in 2006 according to NERC projections; totaling $834K. Additionally, SPP will fund its pro rata share of the costs associated with upgrading the NERC IDC. This cost is expected to total $108K. SPP, as a federally jurisdictional regional transmission organization, is assessed a portion of the operating costs of the Federal Energy Regulatory Commission. SPP’s share of this assessment is based upon the total assessable energy within SPP’s footprint as a percentage of the assessable energy subject to the jurisdiction of the FERC. SPP estimates its share of FERC’s assessment will total $7.2MM. SPP will recover this cost via collections under schedule 12 of the SPP OATT. MEETINGS This item covers the costs associated with SPP hosting meetings. Following is a listing of the various groups for which SPP typically incurs meeting expenses.

• Bandwidth WG • Board of Directors/Members Committee • Coordinated Black Start TF • Corporate Governance Committee • Credit TF • Critical Infrastructure Protection WG • Engineering Task Forces • Finance Committee • Generation WG • Human Resources Committee • Market Implementation TF • Market WG • Markets and Operations Policy Committee • Market Monitoring and Market Power

Mitigation TF • Model Development TF

• NERC CIPC • Operating Reliability WG • Operating Reserve TF • Operational Control TF • Operational Model Development WG • Operations Data WG • Operations Training WG • Regional Planning Summits • Regional State Committee • Regional Tariff WG • Settlements TF • Strategic Planning Committee • System Protection and Control WG • Training Courses • Transmission WG • Voltage & Reactive Management TF

COMMUNICATIONS Communication networks and capability are crucial to SPP in the performance of its required functions. SPP’s system models and state estimator depend on the exchange of timely and reliable information across thousands of data points. SPP ensures communication paths with


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its membership via a dedicated primary private frame-relay network. A separate network provided by another vendor further supports redundancy for this network. Expenditures for this network approximate $1.5MM. SPP also utilizes a high availability fiber network that facilitates transfer of information, primarily related to EIS, across the internet. The fiber network provides aggregate OC48 capacity with DS3 connections to members and ISPs (allowing 600 mega bytes per second information transfer between SPP’s corporate and DR sites) to ensure rapid transmission of information to SPP’s systems and to customers. SPP further utilizes two internet service providers (primary and secondary) to ensure availability through all but the most extreme events. Fiber expenditures cost $840K per year. Other communication expenditures include local and long distance telephone service, including teleconference capability, web casting services, and employee communication capability. LEASES AND MAINTENANCE Increases in staffing have resulted in increased office space requirements for SPP. Currently the Company leases space under a long-term lease expiring in 2011. SPP has negotiated to bring on-line approximately 5,000 additional square feet of space in late 2005. SPP is also tactically re-working its workspace environment to ensure efficient utilization of all available space. Total office lease for 2006 is $679K The market system maintenance agreement was previously budgeted for implementation in 2005 as the EIS market system was brought online. Delays in implementing the EIS market have allowed SPP to defer costs associated with maintenance support of its market system into 2006. The maintenance agreement provides support to the critical functions supported by the EMS network applications, tariff support applications, and the market operations system. The agreement for 2006 will cover critical functions, regardless of the application or database causing the problem, and will have defined priority-based service levels like the prototype agreement tested in 2001. The agreement cost provides for designated, focused support staff, the ability to contact the support staff any time of the day or night, and replication of the SPP environment at the vendor to duplicate and resolve problems. OUTSIDE SERVICES SPP obtains third party expertise to assist in the deployment of its services in a reliable and cost efficient manner. Primary among these services are the management and support of its commercial operations system required in the operation of the EIS market. SPP has also engaged consultants to monitor its markets in an impartial and independent manner. Finally, SPP has engaged a consultant to provide substantial project management assistance to ensure milestones are met as SPP moves to implement its EIS market on May 1, 2006. Total consulting services expenditures budgeted for 2006 dedicated to EIS market total $6.7MM. SPP utilizes numerous software applications specific to performance of electric utility services. These complex applications are further customized to meet the special and specific requirements of SPP’s members and customers. SPP engages consultants, primarily the providers of the applications, to ensure the systems remain updated for known fixes and


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upgraded for needed functionality. Systems requiring these consultants are the EMS (supports control area, reliability coordination, and tariff administration operations); OASIS (provides required transmission service interface to the transmission customer for all activities related to requests for transmission service); and RTO-SS (regional and control area transmission service scheduling system). Expenditures for these services fluctuate based on the needs required by SPP working groups and committees as well as enhancements requested by SPP operations staff. SPP expects these operating expenditures to equal just under $1.4MM during 2006. REGIONAL STATE COMMITTEE The RSC prepared a two-year budget forecasting its administrative costs. These costs are primarily reimbursements for travel and meeting expenditures of individual RSC members and their delegates. CAPITAL EXPENDITURES Significant items in the Capital Budget include: Imbalance Market – Additional capital expenditures are forecast for 2006 to complete the EIS market platform and implement on May 1, 2006. These expenditures are summarized below:

$000 Market Monitoring System $140 Real Time System Enhancements 1,903

Total $2,043 Primary Operations Center – This project will establish a stand-alone operations facility to house SPP’s critical operations, including its coordination center and data center. This site will be able to function completely independently of the main SPP office.

$000 New Facility Shell $3,585 Data Center Assets 3,902

Total $7,487 Maintenance CapEx represents capital expenditures required to maintain SPP’s existing equipment and facilities at their current levels. Components of these items are summarized below:

• Software Licenses to support functions of SPP. Total: $1.1MM. • Hardware includes PCs for existing and new employees; remodeling costs to provide

workspace for staff; security items (firewalls, surveillance equipment); and telephone equipment. Total: $2.4MM.

Capital Funding Account, to fund capital projects of the organization, was established in 2004 with an initial balance of $28.3MM. Current projections indicate the balance of this account will be depleted in October 2006. SPP intends to replenish the balance in this


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account with additional debt financing in the amount of $25MM. Below is a summary of activity in this account $000 Balance January 1, 2004 $28,300 Less: Capital Expenditures 2004 -$7,219 Plus: Interest Earned 2004 $217 Balance December 31, 2004 $21,298 Less: Capital Expenditures YTD 7/2005 -$5,175 Plus: Interest Earned YTD 8/2005 $399 Balance September 30, 2005 $16,522 DEBT PAYMENTS Senior Notes due 2008: SPP will make a $5MM principal payment on its 2008 Senior Notes in March 2006, reducing the remaining principal balance to $10 million; interest costs during the year will total $828K. Senior Notes due 2011: SPP will make interest payments on these notes totaling $1.2MM; outstanding principal balance will remain at $25MM. Beginning June 25, 2007 and annually thereafter through June 25, 2011, SPP will be required to make principal payments in the amount of $5MM. Revolving Line of Credit: SPP maintains an $8MM revolving credit facility. No advances are anticipated under this facility during 2006.

2006 Budget Draft Overview - Finance Committee

2005-06 Change 2005-06 % Change

2003 Actual 2004 Actual 2005 Budget 2006 Budget Draft from Budget from Budget

Tariff Administration Fees 27,451 38,555 40,391 41,369 979 + 2%Member Fees 0 1,118 1,100 1,100 0 + 0%NERC Assessment 0 690 709 942 233 + 33%FERC Fee Assessment 0 0 7,200 7,200 0 + 0%Contract Services Revenue 0 0 0 9,760 9,760 + 0%Miscellaneous Income 2,559 1,503 1,080 1,751 671 + 62%INCOME 30,010 41,865 50,480 62,122 11,643 + 23%

Surplus Carryforward 0 0 4,000 9,724

Salaries & Benefits 12,005 14,499 19,250 29,205 9,955 + 52%Travel 583 613 688 872 183 + 27%Administrative 1,007 1,109 1,939 2,572 632 + 33%Assessments & Fees 623 692 7,909 8,142 233 + 3%Meetings 191 334 399 458 59 + 15%Communications 1,107 1,198 3,159 2,666 (493) - 16%Leases & Maintenance 1,426 2,657 3,565 4,864 1,299 + 36%Outside Services 4,639 7,480 8,553 10,218 1,665 + 19%Regional State Committee 0 3 1,423 449 (974) - 68%Debt Service 1,875 1,875 7,414 7,039 (375) - 5%

OPERATING EXPENSES 23,456 30,459 54,300 66,485 12,185 + 22%

SURPLUS OF INCOME OVER EXPENSES

6,554 11,406 (3,820) (4,362)

253,489 258,558

17.51 17.69 0.18 + 1%

15.93 16.00 0.07 + 0%

Capital Expenditures 1,545 1,545 18,300 13,793 (4,507) - 25%

Billing Determinants

Cost per MWh (in cents) before using PY surplus carryforward

Cost per MWh (in cents)

1

2006 Foundation & Project Budgets

$Thousands Foundation EIS Market ICT New Facility SAS70 TOTAL- - -

Tariff Administration Fees 41,369 - - - - 41,369 Member Fees 1,100 - - - - 1,100 NERC Assessment 942 - - - - 942 FERC Fee Assessment 7,200 - - - - 7,200 Contract Services Revenue - - 9,760 - - 9,760 Miscellaneous Income 1,751 - - - - 1,751

INCOME 52,363 - 9,760 - - 62,122

Salaries & Benefits 23,307 1,062 4,405 103 328 29,205 Travel 699 33 140 - - 872 Administrative 1,974 2 18 178 400 2,572 Assessments & Fees 8,142 - - - - 8,142 Meetings 355 78 26 - - 458 Communications 2,200 394 72 - - 2,666 Leases & Maintenance 2,674 1,840 42 267 41 4,864 Outside Services 4,238 5,926 24 30 - 10,218 Regional State Committee 449 - - - - 449 Interest on Deposits - - - - - -Debt Service 7,039 - - - - 7,039

EXPENSES 51,076 9,335 4,727 578 769 66,485

Headcount 186 11 34 2 3 236

Capital Expenditures 3,862 2,043 401 7,487 - 13,793

2006 Budget Comparisons

Budget '06 vs. Budget '06 vs. Budget '05 vs.2006 Budget 2005 Budget Budget '05 2006 Budget 2005 Projection Projection '05 2005 Budget 2005 Projection Projection '05 2004 Actual

Revenues (000)Tariff Administration Fees 41,369 40,391 979 41,369 44,449 (3,080) 40,391 44,449 (4,059) 38,555 Member Fees 1,100 1,100 0 1,100 1,068 32 1,100 1,068 32 1,078 NERC Assessment 942 709 233 942 709 234 709 709 0 690 FERC Assessment 7,200 7,200 0 7,200 5,868 1,332 7,200 5,868 1,332 0 Contract Services Revenue 9,760 0 9,760 9,760 0 9,760 0 0 0 0 Miscellaneous Income 1,751 1,080 671 1,751 2,469 (718) 1,080 2,469 (1,389) 1,543

TOTAL REVENUES 62,122 50,480 11,643 62,122 54,563 7,559 50,480 54,563 (4,084) 41,865

SURPLUS CARRYFORWARD 9,724 4,000 5,724 9,724 6,000 3,724 4,000 6,000 (2,000) 0

TOTAL REVENUE PLUS SURPLUS 71,846 54,480 17,367 71,846 71,846 54,480 54,480

Expenses (000)Salaries & Benefits

Salaries 18,960 13,216 5,745 18,960 12,166 6,794 13,216 12,166 1,050 10,451 Benefits 6,601 5,281 1,320 6,601 4,425 2,176 5,281 4,425 856 3,486 Board compensation 345 390 (45) 345 318 27 390 318 72 292 Performance compensation plan 2,808 0 2,808 2,808 990 1,818 0 990 (990) 0 Employee expenses 491 364 127 491 339 152 364 339 25 270 Total Salaries & Benefits 29,205 19,250 9,955 29,205 18,238 10,967 19,250 18,238 1,012 14,499

Travel 872 688 183 872 632 240 688 632 56 613

AdministrativeInsurance 1,095 875 220 1,095 847 248 875 847 28 662 Small equipment & software 226 0 226 226 0 226 0 0 0 0 Audits 445 450 (5) 445 504 (59) 450 504 (54) 52 General & office expenses 806 615 191 806 568 238 615 568 47 395 Total Administrative 2,572 1,939 633 2,572 1,919 653 1,939 1,919 20 1,109

Assessments & FeesNERC annual assessment 834 709 125 834 709 125 709 709 (0) 692 NERC IDC upgrade assessment 108 0 108 108 0 108 0 0 0 FERC assessment 7,200 7,200 0 7,200 7,200 0 7,200 7,200 0 0 Total Assessments & Fees 8,142 7,909 233 8,142 7,909 233 7,909 7,909 (0) 692

Meetings 458 399 59 458 366 92 399 366 33 334

Communications 3

2006 Budget Comparisons

Budget '06 vs. Budget '06 vs. Budget '05 vs.2006 Budget 2005 Budget Budget '05 2006 Budget 2005 Projection Projection '05 2005 Budget 2005 Projection Projection '05 2004 Actual

Communications backbone 854 849 5 854 420 434 849 420 429 77 Wide area communications 1,510 1,970 (459) 1,510 970 540 1,970 970 1,000 893 Other 302 341 (39) 302 621 (319) 341 621 (280) 228 Total Communications 2,666 3,159 (493) 2,666 2,011 655 3,159 2,011 1,148 1,198

Leases & MaintenanceLeases 808 746 62 808 703 105 746 703 43 763 Hardware maintenance 801 464 337 801 181 620 464 181 283 200 Software maintenance 3,255 2,354 901 3,255 1,450 1,805 2,354 1,450 904 1,698 Total Leases & Maintenance 4,864 3,565 1,299 4,864 2,334 2,530 3,565 2,334 1,231 2,660

Outside ServicesLegal 1,260 840 420 1,260 1,170 90 840 1,170 (330) 916 Information Technology 2,315 1,762 554 2,315 1,487 828 1,762 1,487 275 1,025 Market Design & Analysis 5,926 5,049 876 5,926 4,993 933 5,049 4,993 56 4,206 Other consulting 717 902 (185) 717 1,214 (497) 902 1,214 (312) 1,333 Total Outside Services 10,218 8,553 1,665 10,218 8,864 1,354 8,553 8,864 (311) 7,480

Regional State CommitteeOperating expenses 249 223 26 249 302 (53) 223 302 (79) 3 Cost benefit study 200 1,200 (1,000) 200 670 (470) 1,200 670 530 0 Total Regional State Committee 449 1,423 (974) 449 972 (523) 1,423 972 451 3

Debt ServiceLoan interest 2,039 2,414 (375) 2,039 2,594 (555) 2,414 2,594 (180) 2,160 Loan principal 5,000 5,000 0 5,000 5,000 0 5,000 5,000 0 0 Total Debt Service 7,039 7,414 (375) 7,039 7,594 (555) 7,414 7,594 (180) 2,160

TOTAL OPERATING EXPENSES 66,485 54,300 12,186 66,485 50,839 15,646 54,300 50,839 3,460 30,747

BILLING DETERMINANTS 258,558 253,489 5,070 258,558 258,558 253,489 253,489

Gross Cost per MWh (in cents) 19.76 17.51 2.25 19.76 19.76 17.51 17.51 (before using surplus carryforward)

Cost per MWh (in cents) 16.00 15.93 0.07 16.00 16.00 15.93 15.93

Depreciation & AmortizationDepreciation 7,404 4,800 2,604 7,404 2,531 4,872 4,800 2,531 2,269 5,280 Amortization 41 81 (40) 41 82 (41) 81 82 (1) 61 Total Depreciation/Amortization 7,444 4,881 2,563 7,444 2,613 4,831 4,881 2,613 2,268 5,341

4

Foundation

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


Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec 2006 Total

33 48 33 28 55 22 24 33 23 23 13 13 348 11 11 11 11 11 11 11 11 11 11 11 11 136

1,138 1,138 1,139 1,140 1,143 1,144 1,144 1,143 1,142 1,142 1,142 1,142 13,695 126 126 126 126 126 124 127 127 127 127 127 127 1,515 17 17 17 17 17 17 17 17 17 17 17 17 209 47 47 47 47 47 47 47 47 46 46 44 44 553

182 182 182 182 182 183 183 183 183 183 183 183 2,191 54 54 54 54 54 54 54 54 54 54 54 54 652 75 75 75 74 74 73 71 69 66 64 61 60 836 71 71 71 71 71 75 75 75 75 75 75 75 879 93 93 93 93 93 93 93 93 93 93 93 93 1,116 42 42 42 42 42 42 42 42 42 42 42 42 504 70 - - - - 5 - - - - - - 75 96 - - - - 12 - - - - - - 108 7 2 1 1 1 1 1 1 1 1 1 1 14

18 6 1 1 1 1 1 1 1 1 1 1 34 32 13 15 40 101 34 32 4 15 36 0 25 345 8 8 8 8 8 8 8 8 8 8 8 8 96

2,119 1,933 1,915 1,935 2,026 1,946 1,930 1,908 1,904 1,924 1,873 1,897 23,307

Foundation 5


Tariff Administration Fees - - - - - - - - - - - - -Member Fees - - - - - - - - - - - - -NERC Assessment - - - - - - - - - - - - -FERC Fee Assessment - - - - - - - - - - - - -Contract Services Revenue - - - - - - - - - - - - -Miscellaneous Income - - - - - - - - - - - - -

INCOME - - - - - - - - - - - - -


Salaries & BenefitsStaff Additions 6 6 6 6 6 6 6 6 6 6 6 6 66 Staff Additions 11 11 11 11 11 11 11 11 11 11 11 11 132 Staff Additions 5 5 5 5 5 5 5 5 5 5 5 5 66 Existing Salaries 10 10 10 10 10 10 10 10 10 10 10 10 117 Staff Additions 11 11 11 11 11 11 11 11 11 11 11 11 132 Existing Salaries 15 15 15 15 15 15 15 15 15 15 15 15 183 Dental Insurance 1 1 1 1 1 1 1 1 1 1 1 1 8 Dental Insurance 1 1 1 1 1 1 1 1 1 1 1 1 6 Health Insurance 7 7 7 7 7 7 7 7 7 7 7 7 79 Health Insurance 6 6 6 6 6 6 6 6 6 6 6 6 66 Medicare (1.45%) Total 0 0 0 0 0 0 0 0 0 0 0 0 6 Medicare (1.45%) Total 0 0 0 0 0 0 0 0 0 0 0 0 4 Performance Compensation Total 9 9 9 9 9 9 9 9 9 9 9 9 104 Savings Plan (4.5%) 3 3 3 3 3 3 3 3 3 3 3 3 31 Social Security (6.2%) 3 3 3 3 3 3 3 3 3 3 3 3 31 Hiring Expense 30 - - - - - - - - - - - 30 EIS Salary & Benefit Total 116 86 86 86 86 86 86 86 86 86 86 86 1,062

EIS Market



EIS Market


TravelMarkets:Market Design & Analysis 2 1 2 2 1 1 2 1 2 2 1 1 19 Markets:Market Monitoring 1 1 2 - 1 3 - 1 3 - 1 3 14 EIS Travel Total 3 2 4 2 2 4 2 2 5 2 2 3 33 AdministrativeDues - - - - - - - - - - - 1 1 Dues - - - - 1 - - - - - 1 - 1 EIS Administrative Total - - - - 1 - - - - - 1 1 2

Assessments & Fees -

MeetingsMarket Implementation TF 3 3 3 3 3 3 - - - - - - 18 Market WG 3 3 3 3 3 3 3 3 3 3 3 3 30 Training - - - - - - - - - - - 1 1 Training:Market Training Follow-Up - - - - - 3 3 3 3 3 - - 15 Training:Market Training Follow-Up - - - - - 3 3 3 3 3 - - 14 EIS Meetings Total 6 6 6 6 6 11 8 8 8 8 3 3 78

CommunicationsSPPNET, Primary 13 13 13 13 13 13 13 13 13 16 16 16 164 SPPNET, Primary 3 3 3 3 3 3 3 3 3 4 4 4 41 SPPNET, Secondary 5 5 5 5 5 5 5 5 5 7 7 7 70 SPPNET, Secondary 1 1 1 1 1 1 1 1 1 2 2 2 17 OATI SPPNET Connection Fee 0 0 0 0 0 0 0 0 0 0 0 0 2 OATI SPPNET Connection Fee 0 0 0 0 0 0 0 0 0 0 0 0 0 Internet:Internet Services:Primary Intern 4 4 4 4 4 4 4 4 4 4 4 4 52 Internet:Internet Services:Secondary Inte 4 4 4 4 4 4 4 4 4 4 4 4 45 E-Mail Internet services 0 0 0 0 0 0 0 0 0 0 0 0 3 EIS Communications Total 31 31 31 31 31 31 31 31 31 38 38 38 394


EIS Market


Leases & MaintenanceMAINTENANCE - Software:Software - O 1,323 - - 35 160 - 19 - - - - 300 1,837 MAINTENANCE - Software:Software - - 2 - - - - - 1 - - - 3 EIS Lease & Maintenance Total 1,323 - 2 35 160 - 19 - 1 - - 300 1,840

Outside ServicesProduction Costs 349 349 349 349 349 349 349 349 349 349 349 349 4,192 Project assistance 147 147 147 147 147 147 - - - - - - 883 Economist Vendor 50 50 50 300 50 50 50 50 50 50 50 50 850 EIS Outside Services Total 547 547 547 797 547 547 399 399 399 399 399 399 5,926

Regional State Committee 0 0 0 0 0 0 0 0 0 0 0 0 0

Interest on Deposits 0 0 0 0 0 0 0 0 0 0 0 0 0

Debt Service 0 0 0 0 0 0 0 0 0 0 0 0 0

EXPENSES 2,024 672 675 957 831 679 546 527 531 533 528 830 9,334


Tariff Administration Fees - - - - - - - - - - - - -Member Fees - - - - - - - - - - - - -NERC Assessment - - - - - - - - - - - - -FERC Fee Assessment - - - - - - - - - - - - -Contract Services Revenue 400 400 450 450 450 952 952 998 998 998 998 1,057 9,103 Miscellaneous Income - - - - - - - - - - - - -

INCOME 400 400 450 450 450 952 952 998 998 998 998 1,057 9,103

Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec 2006 TotalSalaries & BenefitsContinuing Education - - - 3 - - 3 - - 3 - - 8 Continuing Education - - - - - 3 3 3 3 3 3 3 18 Continuing Education - - - - - 3 - - 3 - - - 5 Continuing Education - - - - - 3 - - 3 - - 3 8 Continuing Education - - - - - 3 - - - 3 - - 5 Dental Insurance 0 0 0 0 0 0 0 0 0 0 0 0 3 Dental Insurance 1 1 1 1 1 1 1 1 1 1 1 1 8 Dental Insurance 1 1 1 1 1 1 1 1 1 1 1 1 9 Dental Insurance 0 0 0 0 0 0 0 0 0 0 0 0 4 Dental Insurance 1 1 1 1 1 1 1 1 1 1 1 1 9 Existing Salaries 15 15 15 15 15 15 15 15 15 15 15 15 175 Existing Salaries 8 8 8 8 8 8 8 8 8 8 8 8 98 Health Insurance 3 3 3 3 3 3 3 3 3 3 3 3 37 Health Insurance 7 7 7 7 7 7 7 7 7 7 7 7 87 Health Insurance - - - - - - - - - - - - -Health Insurance 4 4 4 4 4 4 4 4 4 4 4 4 49 Health Insurance 8 8 8 8 8 8 8 8 8 8 8 8 99 Medicare (1.45%) 0 0 0 0 0 0 0 0 0 0 0 0 5 Medicare (1.45%) 1 1 1 1 1 1 1 1 1 1 1 1 8 Medicare (1.45%) 1 1 1 1 1 1 1 1 1 1 1 1 11

Contract Services



Contract Services


Medicare (1.45%) 0 0 0 0 0 0 0 0 0 0 0 0 5 Medicare (1.45%) 1 1 1 1 1 1 1 1 1 1 1 1 10 Merit Increase 1 1 1 1 1 1 1 1 1 1 1 1 13 Merit Increase 2 2 2 2 2 2 2 2 2 2 2 2 23 Merit Increase 2 2 2 2 2 2 2 2 2 2 2 2 26 Merit Increase 1 1 1 1 1 1 1 1 1 1 1 1 13 Merit Increase 2 2 2 2 2 2 2 2 2 2 2 2 28 Performance Compensation 4 4 4 4 4 4 4 4 4 4 4 4 48 Performance Compensation 7 7 7 7 7 7 7 7 7 7 7 7 87 Performance Compensation 10 10 10 10 10 10 10 10 10 10 10 10 114 Performance Compensation 4 4 4 4 4 4 4 4 4 4 4 4 50 Performance Compensation 9 9 9 9 9 9 9 9 9 9 9 9 104 Savings Plan (4.5%) 1 1 1 1 1 1 1 1 1 1 1 1 14 Savings Plan (4.5%) 2 2 2 2 2 2 2 2 2 2 2 2 26 Savings Plan (4.5%) 3 3 3 3 3 3 3 3 3 3 3 3 34 Savings Plan (4.5%) 1 1 1 1 1 1 1 1 1 1 1 1 15 Savings Plan (4.5%) 3 3 3 3 3 3 3 3 3 3 3 3 31 Social Security (6.2%) 2 2 2 2 2 2 1 1 1 1 1 1 16 Social Security (6.2%) 3 3 3 3 3 3 3 3 3 3 3 3 36 Social Security (6.2%) 4 4 4 4 4 4 4 4 4 4 4 4 47 Social Security (6.2%) 2 2 2 2 2 2 2 2 2 2 2 2 20 Social Security (6.2%) 4 4 4 4 4 4 4 4 4 4 4 4 43 Staff Additions 12 12 12 12 12 12 12 12 12 12 12 12 145 Staff Additions 40 40 40 40 40 40 40 40 40 40 40 40 479 Staff Additions 63 63 63 63 63 63 63 63 63 63 63 63 761 Staff Additions 28 28 28 28 28 28 28 28 28 28 28 28 331 Staff Additions 58 58 58 58 58 58 58 58 58 58 58 58 695 Hiring Expense 10 - - - - - - - - - - - 10 Hiring Expense 15 - - - - - - - - - - - 15 Hiring Expense 20 - - - - - - - - - - - 20 Hiring Expense 10 - - - - - - - - - - - 10


Contract Services


Hiring Expense 20 - - - - - - - - - - - 20 Relocation Expense 12 - - - - - - - - - - - 12 Relocation Expense 36 - - - - - - - - - - - 36 Relocation Expense 48 - - - - - - - - - - - 48 Relocation Expense 24 - - - - - - - - - - - 24 Relocation Expense 48 - - - - - - - - - - - 48 Staff Additions 11 11 11 11 11 11 11 11 11 11 11 11 132 Staff Additions 5 5 5 5 5 5 5 5 5 5 5 5 66 Dental Insurance 0 0 0 0 0 0 0 0 0 0 0 0 4 Health Insurance 3 3 3 3 3 3 3 3 3 3 3 3 40 Medicare (1.45%) Total 0 0 0 0 0 0 0 0 0 0 0 0 3 Performance Compensation Total 2 2 2 2 2 2 2 2 2 2 2 2 30 Savings Plan (4.5%) 1 1 1 1 1 1 1 1 1 1 1 1 9 Social Security (6.2%) 1 1 1 1 1 1 1 1 1 1 1 1 12 Hiring Expense 10 - - - - - - - - - - - 10 Contract Services Salary & Benefits Total 596 343 343 345 343 353 347 345 350 350 345 347 4,405

TravelContract Services 20 20 10 10 10 10 10 10 10 10 10 10 140 Contract Services Travel Total 20 20 10 10 10 10 10 10 10 10 10 10 140

AdministrativeHardware-ICT 2 - - - - - - - - - - - 2 Hardware-ICT 6 - - - - - - - - - - - 6 Hardware-ICT 2 - - - - - - - - - - - 2 Hardware-ICT 1 - - - - - - - - - - - 1 Software-ICT 6 - - - - - - - - - - - 6 Software-ICT 3 - - - - - - - - - - - 3 Contract Services Administrative Total 18 - - - - - - - - - - - 18


Contract Services


Assessments & Fees

MeetingsICT - - - 2 - - 10 - 2 10 - 2 26 Contract Services Meetings Total - - - 2 - - 10 - 2 10 - 2 26

CommunicationsO&M:Cellular Phone Services-ICT 1 1 1 1 1 1 1 1 1 1 1 1 7 ICT Circuit to Entergy - PB 5 5 5 5 5 5 5 5 5 5 5 5 61 O&M:Wireless Modem Services-ICT 0 0 0 0 0 0 0 0 0 0 0 0 3 Contract Services Communications Total 6 6 6 6 6 6 6 6 6 6 6 6 72

Leases & MaintenanceLeases:Office Space, New Orleans 4 4 4 4 4 4 4 4 4 4 4 4 42 Contract Services Lease & Maintenance Total 4 4 4 4 4 4 4 4 4 4 4 4 42

Outside ServicesContract Services 2 2 2 2 2 2 2 2 2 2 2 2 24 Contract Services Outside Services Total 2 2 2 2 2 2 2 2 2 2 2 2 24

Regional State Committee

Interest on Deposits

Debt Service

EXPENSES 645 374 364 369 364 374 379 366 373 381 366 371 4,727

New FacilityJan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Total


INCOME - - - - - - - - - - - - -

Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec 2006 TotalSalaries & BenefitsStaff Additions - - - - - 4 4 4 4 4 4 4 30 Staff Additions - - - - - 4 4 4 4 4 4 4 30 Dental Insurance - - - - - 0 0 0 0 0 0 0 2 Health Insurance - - - - - 2 2 2 2 2 2 2 15 Medicare (1.45%) Total - - - - - 0 0 0 0 0 0 0 1 Performance Compensation Total - - - - - 1 1 1 1 1 1 1 9 Savings Plan (4.5%) - - - - - 0 0 0 0 0 0 0 3 Social Security (6.2%) - - - - - 1 1 1 1 1 1 1 4 Hiring Expense - - - - - 10 - - - - - - 10 New Facility Salary & Benefit Total - - - - - 23 13 13 13 13 13 13 103

Travel

AdministrativeEnergy Usage - - - - - 6 6 6 6 6 6 6 42 Generator Fuel - - - - - - - 10 - 0 0 0 11 Hardware - - - - - - - - - 40 - - 40 Hardware - - - - - - - - - 58 - - 58 Hardware - - - - - - - - - 15 - - 15 Property Tax - - - - - - - - - 12 - - 12 New Facility Administrative Total - - - - - 6 6 16 6 131 6 6 178


New FacilityJan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Total


Assessments & Fees

Meetings

Communications

Leases & MaintenanceMaintenance -- Hardware -- Servers - - - - - - - - - 226 - - 226 MAINTENANCE - Software:Software - O - - - 41 - - - - - - - - 41 New Facility Lease & Maintenance Total - - - 41 - - - - - 226 - - 267

Outside ServicesAdministration:Human Resources - - - - - - - - - 10 10 10 30 New Facility Outside Services Total - - - - - - - - - 10 10 10 30



Debt Service

EXPENSES - - - 41 - 29 19 29 19 381 30 30 578

SAS70Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Total


INCOME - - - - - - - - - - - - -

Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec 2006 TotalSalaries & BenefitsStaff Additions 12 12 12 12 12 12 12 12 12 12 12 12 146 Staff Additions 5 5 5 5 5 5 5 5 5 5 5 5 66 Dental Insurance 0 0 0 0 0 0 0 0 0 0 0 0 4 Health Insurance 3 3 3 3 3 3 3 3 3 3 3 3 40 Medicare (1.45%) Total 0 0 0 0 0 0 0 0 0 0 0 0 3 Performance Compensation Total 3 3 3 3 3 3 3 3 3 3 3 3 32 Savings Plan (4.5%) 1 1 1 1 1 1 1 1 1 1 1 1 10 Social Security (6.2%) 1 1 1 1 1 1 1 1 1 1 1 1 13 Hiring Expense 15 - - - - - - - - - - - 15 SAS70 Salary & Benefit Total 41 26 26 26 26 26 26 26 26 26 26 26 328

Travel

AdministrativeSAS70 Audit - 100 - - 100 - - 100 - - 100 - 400 SAS70 Administrative Total - 100 - - 100 - - 100 - - 100 - 400

Assessments & Fees


SAS70Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Total


Meetings

Communications

Leases & MaintenanceMAINTENANCE - Software:Software - - - - - - 41 - - - - - 41 SAS70 Lease & Maintenance Total - - - - - - 41 - - - - - 41

Outside Services



Debt Service

EXPENSES 41 126 26 26 126 26 67 126 26 26 126 26 769

2006 Cash Flow ProjectionsOperating and Capital

OPERATING CASH (000) January February March April May June July August September October November December January 2006

Beginning Cash on Hand 10,500 7,220 8,237 3,459 4,076 4,699 5,226 (564) 1,241 2,433 3,821 5,527 6,565,479$

Assessments 3,447 3,447 3,447 3,447 3,447 3,447 3,447 3,447 3,447 3,447 3,447 3,447 Member Fees 0 1,100 0 0 0 0 0 0 0 0 0 0 NERC Assessment 209 86 0 209 22 0 209 0 0 209 0 0 FERC Fee Assessment 600 600 600 600 600 600 600 600 600 600 600 600 Contract Services Revenue 400 400 450 450 450 952 952 998 998 998 998 1,057 Miscellaneous Income 67 219 58 217 54 211 49 208 47 269 97 256 Operating Income 4,722 5,853 4,555 4,923 4,573 5,210 5,257 5,253 5,092 5,523 5,143 5,360

Salaries & Benefits 2,748 3,191 2,177 2,202 2,290 2,242 2,211 2,184 2,184 2,203 2,147 2,173 Travel 89 90 82 80 64 78 71 61 76 81 60 62 Administrative 1,291 151 82 81 137 92 80 164 46 239 143 65 Assessments & Fees 209 86 0 209 22 0 7,409 0 0 209 0 0 Meetings 70 18 66 27 24 48 39 21 48 40 19 39 Communications 214 217 214 214 215 215 215 215 215 244 244 244 Leases & Maintenance 2,303 223 115 276 287 521 157 88 120 323 86 390 Outside Services 1,059 839 913 1,197 891 869 843 694 716 776 717 729 Regional State Committee 21 21 121 21 21 21 21 21 121 21 21 21 Debt Service 0 0 5,563 0 0 598 0 0 375 0 0 598

Operating Expenses 8,003 4,836 9,333 4,306 3,950 4,683 11,047 3,448 3,900 4,136 3,437 4,321

Cash Surplus/(Deficit) for month

(3,280) 1,017 (4,777) 617 623 526 (5,790) 1,806 1,192 1,387 1,706 1,039

Ending Cash on Hand 7,220 8,237 3,459 4,076 4,699 5,226 (564) 1,241 2,433 3,821 5,527 6,565

CAPITAL CASH (000) January February March April May June July August September October November December

Beginning Cash on Hand 10,400 7,588 7,008 6,518 5,599 5,066 4,557 4,006 3,573 27,088 22,553 21,897 21,926,832$

Capital Expenditures 2,838 599 508 935 547 522 563 443 1,494 4,605 713 26

Interest (26) (19) (18) (17) (14) (13) (12) (10) (9) (69) (57) (56) Additional Borrowings 25,000 Ending Cash on Hand 7,588 7,008 6,518 5,599 5,066 4,557 4,006 3,573 27,088 22,553 21,897 21,927

TOTAL CASH (000) 20,900 14,808 15,245 9,978 9,675 9,766 9,783 3,441 4,814 29,522 26,373 28,492

17

2006 Cash Flow

(5,000,000)

-

5,000,000

10,000,000

15,000,000

20,000,000

25,000,000

30,000,000

December2005

January2006

February March April May June July August September October November December

Mon

th E

nd C

ash

on H

and

Operating Cash (000s) Capital Cash (000s)

2006 Capital Expenditures

Corporate IT IT ContractAdministration Affairs Engineering Applications Infrastructure Markets Operations Regulatory RSC Services TOTAL

Capital Expenditure Project (000)Corporate Website Development 0 30 0 0 0 0 0 0 0 0 30 Current Facility Improvements 355 0 0 0 0 0 0 0 0 0 355 Entergy ICT 30 0 0 0 371 0 0 0 0 0 401 Maintenance - Hardware 0 6 41 0 2,351 0 0 0 0 0 2,398 Maintenance - Software 7 0 75 341 656 0 0 0 0 0 1,079 Market Project 0 0 0 0 0 2,043 0 0 0 0 2,043 New Facility 3,585 0 0 0 3,902 0 0 0 0 0 7,487

Total Capital Expenditures 3,977 36 116 341 7,280 2,043 0 0 0 0 13,793

19

Capital Expenditures

Capital Expenditure Item Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec TotalCorporate website redevelopment and design - - - 30 - - - - - - - - 30 Corporate Website Development Total - - - 30 - - - - - - - - 30

Purchase furniture for new hires 75 - - 75 - - 75 - - 75 - - 300 Remodel existing 1st Floor - Sound System 20 - - - - - - - - - - - 20 Remodel existing 6th Floor 35 - - - - - - - - - - - 35 Current Facility Improvements Total 130 - - 75 - - 75 - - 75 - - 355

Purchase furniture for Ict, New Orleans 30 - - - - - - - - - - - 30 Operations -- ICT -- Communications Equip > $1,000 39 - - - - - - - - - - - 39 Operations -- ICT -- Desktop/Laptop PC's 11 - - - - - - - - - - - 11 Operations -- ICT -- Printers > $1,000 9 - - - - - - - - - - - 9 Operations -- ICT -- Servers 75 - - - - - - - - - - - 75 Operations -- ICT -- Software Licenses > $1,000 198 - - - - - - - - - - - 198 Operations -- New Facility-ICT -- Desktop/Laptop PC's - - - - - - - - - 36 - - 36 Operations -- New Facility-ICT -- Printers > $1,000 - - - - - - - - - 3 - - 3 Entergy ICT Total 362 - - - - - - - - 39 - - 401

Record retention - - - - - - - - 3 - - - 3 72" SmartBoard SB580 with Accessories 4 - - - - - - - - - - - 4 MOD Servers - 30 - - - - - - - - - - 30 New MarketSYM Server for Expansion Planning - - 8 - - - - - - - - - 8 Fireproof File Cabinet 3 - - - - - - - - - - - 3 General Office -- Desktop/Laptop PC's 38 - - - - - - - - - - - 38 General Office -- Desktop/Laptop PC's 34 - - - - - - - - - - - 34 General Office -- Desktop/Laptop PC's 14 - - - - - - - - - - - 14 General Office -- Desktop/Laptop PC's 44 - 3 9 3 - - - 3 - - 3 65 General Office -- Desktop/Laptop PC's 22 - - 3 - - - - 3 - - - 28 General Office -- Desktop/Laptop PC's 71 - 6 16 9 11 3 - 6 - 3 - 125 General Office -- Miscellaneous Hardware > $1,000 1 - - - - - - - - - - - 1 General Office -- Printers > $1,000 5 - 13 - - - - - - 3 - - 21 General Office -- Servers 28 - - 10 - - - - - - - - 38 Operations -- AECC -- Desktop/Laptop PC's - - - - - - - - - - - - -Operations -- AECC -- Printers > $1,000 - - - - - - - - - - - - -Operations -- AECC -- Servers - - - 6 - - - - - - - - 6 Operations -- AECC -- Servers - - - - - - - - - 7 - - 7 Operations -- Plaza West -- Desktop/Laptop PC's 32 - - - - - - - - - - - 32 Operations -- Plaza West -- Printers > $1,000 - - 3 - - - - - - - - - 3 Operations -- Plaza West -- Printers > $1,000 - - - - - - - - - - - - -Operations -- Plaza West -- Servers - - - - - - - - - - - - -Operations -- Plaza West -- Servers 174 - - - - - - - - - - - 174 Operations -- Plaza West -- Servers 24 - - - - - - - - - - - 24 Operations -- Plaza West -- Servers 547 - - 8 - - 14 - 21 7 - - 597 General Office -- Communications Equip > $1,000 2 13 4 64 - - 6 - - 723 - - 812 General Office -- Security Equipment > $1,000 100 - - - - 25 - - - - - - 125 General Office -- Security Equipment > $1,000 8 - - - - - - - - - - - 8 General Office -- Servers 8 - - - - - - - - - - - 8 Operations -- AECC -- Communications Equip > $1,000 - - - - - - - - - - - - -Operations -- Plaza West -- Communications Equip > $1,000 120 - - 48 - - - - - - - - 168 Operations -- Plaza West -- Servers 26 - - - - - - - - - - - 26


Capital Expenditures 20

Capital Expenditures

Capital Expenditure Item Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Total


Maintenance - Hardware Total 1,303 43 36 164 12 36 23 - 36 740 3 3 2,398

License for One Additional Seat CMS - - 7 - - - - - - - - - 7 IRP Section Tools 75 - - - - - - - - - - - 75 Software:AREVA EMS Change Orders 3 3 3 3 3 3 3 3 3 3 3 3 36 Software:OASIS Change Orders - - - - - 25 - - - - - - 25 Software:OASIS Automation Change Orders - - 20 - - 20 - - 20 - - 20 80 Software:OATI Change Orders - 50 - - 50 - - 50 - - 50 - 200 General Office -- Software Licenses > $1,000 80 - - - - - - - - - - - 80 General Office -- Software Licenses > $1,000 95 - - - - - - - - - - - 95 General Office -- Software Licenses > $1,000 116 26 4 39 5 1 2 - - 1 2 - 196 Operations -- AECC -- Software Licenses > $1,000 - - - - - - - - - - - - -Operations -- Plaza West -- Software Licenses > $1,000 200 - - - - - - - - - - - 200 Operations -- Plaza West -- Software Licenses > $1,000 10 - - - - - - - - - - - 10 General Office -- Software Licenses > $1,000 27 - - 40 - - - - - - - - 67 Operations -- Plaza West -- Software Licenses > $1,000 - - - 8 - - - - - - - - 8 Maintenance - Software Total 607 79 34 89 58 49 5 53 23 4 55 23 1,079

Spot Balancing Market 147 147 147 287 147 147 140 100 140 100 400 - 1,903 Market Monitoring system enhancements - 40 - - 40 - 30 - 30 - - - 140 Market Project Total 147 187 147 287 187 147 170 100 170 100 400 - 2,043

Purchase furniture for new facility - - - - - - - - 25 - - - 25 Purchase furniture for new facility - - - - - - - - 370 - - - 370 Purchase furniture for new facility - - - - - - - - 40 - - - 40 Purchase furniture for new facility - - - - - - - - 20 - - - 20 Purchase furniture for new facility - - - - - - - - 20 - - - 20 Purchase furniture for new facility - - - - - - - - 500 - - - 500 Construction of new facility 290 290 290 290 290 290 290 290 290 - - - 2,610 Operations -- New Facility -- Desktop/Laptop PC's - - - - - - - - - 70 - - 70 Operations -- New Facility -- Desktop/Laptop PC's - - - - - - - - - 24 - - 24 Operations -- New Facility -- Printers > $1,000 - - - - - - - - - 9 - - 9 Operations -- New Facility -- Printers > $1,000 - - - - - - - - - 3 - - 3 Operations -- New Facility -- Servers - - - - - - - - - 98 - - 98 Operations -- New Facility -- Servers - - - - - - - - - 318 - - 318 Operations -- New Facility -- Servers - - - - - - - - - 22 - - 22 Operations -- New Facility -- Servers - - - - - - - - - 1,319 255 - 1,574 Operations -- New Facility -- Software Licenses > $1,000 - - - - - - - - - 610 - - 610 Operations -- New Facility -- Software Licenses > $1,000 - - - - - - - - - 65 - - 65 Operations -- New Facility -- Software Licenses > $1,000 - - - - - - - - - 31 - - 31 Operations -- New Facility -- Software Licenses > $1,000 - - - - - - - - - 219 - - 219 Operations -- New Facility -- Communications Equip > $1,000 - - - - - - - - - 469 - - 469 Operations -- New Facility -- Security Equipment > $1,000 - - - - - - - - - 361 - - 361 Operations -- New Facility -- Servers - - - - - - - - - 8 - - 8 Operations -- New Facility -- Software Licenses > $1,000 - - - - - - - - - 21 - - 21 New Facility Total 290 290 290 290 290 290 290 290 1,265 3,647 255 - 7,487

Grand Total 2,838 599 508 935 547 522 563 443 1,494 4,605 713 26 13,793

Capital Expenditures 21

Three Year Budget Projection2007-2009

2006 2007 2008 2009 Trend

Tariff Administration Fees 41,408 42,236 48,466 49,435 Member Fees 1,100 2,200 (a) 2,244 2,289 2%NERC Assessment 942 859 (b) 885 912 5%FERC Fee Assessment 7,200 7,344 7,491 7,641 2%Contract Services Revenue 9,760 26,500 (c) 34,000 41,500 Miscellaneous Income 1,751 1,839 1,931 2,027 5%

INCOME 62,161 80,978 95,017 103,804 Surplus carryforward 9,724 5,416 132 139 Net Total 71,885 86,394 95,148 103,943

Salaries & Benefits (d) 29,205 32,871 35,527 38,101 5%Travel 872 898 925 953 3%Administrative 2,572 2,649 2,728 2,810 3%Assessments & Fees 8,142 8,203 8,376 8,552 3%Meetings 458 468 477 487 2%Communications 2,666 2,684 3,088 3,331 Leases & Maintenance 4,864 5,010 5,160 5,315 3%Outside Services 10,218 7,434 (e) 7,657 7,887 3%Contract Services Expenses - 12,555 (c) 18,180 23,805 Regional State Committee 449 462 476 490 3%Debt Service 7,023 13,029 (f) 12,415 11,997

EXPENSES 66,469 86,263 95,009 103,729

Billing Determinants 258,800 263,976 269,256 274,641 Cost per MWh (in cents) 16.00 16.00 18.00 18.00

41,408,000 42,236,160 48,465,994 49,435,313

Capital Expenditures 13,793 11,034 8,828 7,062 (20%)

(e) Outside Services declined due to implementation of the EIS Market.

(f) Debt service calculation is projected based upon receiving new financiing in 2006.

General: The Market Development group is not projecting any costs will be incurred for additional phases of the market implementation.

(a) Member fees are designed to cover the cost of SPP's reliability function. This projection increases the Member Fee collction to near that amount.

(b) The 2006 budget has a $108,000 special project, this has been removed for trending

(c) Increase per Bruce Rew, Executive Director, Conract Services. Associated expenses are projected at 75% of revenue and are included as a separate expense line item for 2007-09. Expenses related to Contract Services are in the appropriate expense category for 2006.

(d) Operations is projecting to implement a single control area covering the SPP footprint in 2007. Additional staffing would include one supervisor and six operations personnel in 2007. Additional staff positions for other areas of the company are projected at 10 for 2007, 8 for 2008, and 6 for 2009.

Southwest Power Pool FINANCE COMMITTEE

Recommendation to the Board of Directors October 25, 2005

Assessment and Tariff Schedule 1 Rate for 2006

Roster Harry Skilton, Chair Director Larry Altenbaumer Director Gary Voigt Arkansas Electric Cooperatives Corp. Trudy Harper Tenaska Doug Henry Westar Energy Michael Desselle American Electric Power Background The Board of Directors establishes the assessment and administrative fee rates utilized by SPP to recover its annual revenue requirement. The Finance Committee monitors the rates established by the Board of Directors and recommends adjustments to the rates as conditions warrant. Analysis SPP’s net revenue requirement as outlined in its 2006 budget is $36MM (adjusted for 2005’s forecasted surplus of $9.7MM). SPP staff estimates 2006 billing determinants of 258,558,000 MWh; indicating a required rate of $0.1392/MWh in order to remain cash neutral during 2006. SPP’s forecast revenue requirement in 2006, prior to adjustment for the 2005 carryover surplus, is $45.7MM or $0.1768/MWh. SPP is scheduled to begin repayment of its 4.78% Senior Notes due 2011 in 2007 which, all other items being equal, will result in an increase in the revenue requirement to $50.7MM or $0.1961/MWh. Should SPP maintain its administrative fee rate at $0.16/MWh during 2006, SPP would expect to carry a surplus of $5.4MM into 2007. Recommendation The Finance Working Group recommends the SPP Board of Directors establish an assessment and tariff schedule 1 rate of $0.16/MWh effective January 1, 2006. Approved Finance Committee October 11, 2005 Action Requested Approve Recommendation

Southwest Power Pool, Inc. FINANCE COMMITTEE

Report to the Board of Directors October 25, 2005

Organizational Roster The following members represent the Credit Task Force:

Nithya Venkatesan NRG Tricia Harrod Aquila Jason Hill Aquila Brian Lawson GDS Associates, representing ETEC Lanny Keele Capline Morgan Davies Calpine Mark Soulliere Tenaska Stephanie Staska Cargill Ross Baker Aces Power Terry Smith The Energy Authority representing City Utilities of Springfield

Background The Credit Task Force was formed in November 2003 and charged with reviewing and developing credit policies and procedures to support transactions occurring under the SPP regional tariff. The Credit Task Force presented to the Finance Committee a revised Credit Policy at the Finance Committee’s March 29, 2005 meeting. The Finance Committee approved the Credit Policy as drafted, directed SPP staff to present the Credit Policy to the MOPC and request review by the RTWG to prepare the policy for submission with the SPP regional tariff, and ordered implementation of the Credit Policy as soon as practicable following acceptance by the SPP Board of Directors. The SPP Board of Directors, at their April 26, 2005 meeting, approved a recommendation from the Finance Committee to adopt the Credit Policy and implement the policy as soon as practicable but no later than the filing of the energy imbalance market rules. The Finance Committee, at the July 26, 2005 meeting of the SPP Board of Directors, resolved to file the Credit Policy with the October tariff filing.

Analysis The Credit Task Force met 4 times in September 2005 to finalize aspects of the Credit Policy implementation and address ancillary credit issues related to implementation of the Energy Imbalance Services market (“EIS”). A topic of discussion centered upon the appropriateness of implementing the Credit Policy in advance of a filing with the Commission and the consequences of doing so. A similar action in PJM resulted in PJM being required to revert back to its prior policy until the Commission was able to rule on the new policy1. SPP’s regulatory counsel participated in the meeting and was familiar with the PJM ruling. A suggestion was made to implement the policy coincident with filing the policy with the Commission. SPP believes the policy will have numerous interventions and general practice has been to implement coincident with a filing when it is believed there will be minimal interventions. A recommendation was made to recommend to the Finance Committee the Credit Policy be filed with the Commission and implementation delayed until definitive action by the Commission on the filing. This recommendation was approved with one nay vote.

1 See FERC docket ELO3-207-000

The Credit Task Force also discussed in detail the potential exposure calculation detailed within the Credit Policy. The Credit Task Force had approved the exposure calculations in meetings held in late 2004. The approved exposure calculation for EIS activity is based on the highest day’s charges incurred over the preceding year while the exposure calculation for transmission service is based on the highest monthly A/R balance over the past year. The issue raised concerned the “punitive” nature of the calculations and whether they are appropriate measures of potential exposure.

A sub-group of the Credit Task Force collaborated and developed a new methodology for calculation of potential exposure to services sold through the regional tariff. This language was approved by the Credit Task Force at its October 7, 2005 meeting with 0 nay votes

Recommendation The Finance Committee recommends the Credit Policy previously approved by the SPP Board of Directors at its April 25, 2005 meeting be amended to include the attached language concerning calculation of potential exposure. The Finance Committee further recommends the Credit Policy be filed separate from the EIS filings to allow for a request for expedited review. Additionally, the Finance Committee recommends implementation of the Credit Policy be delayed until FERC completes its review and action on the Credit Policy filing.

Approved: Credit Task Force

Finance Committee – unanimous vote

October 7, 2005

October 11, 2005

Action Requested: Approve recommendation

ARTICLE FIVE Calculation of Total Potential Exposure

5.1 Overview. The Total Potential Exposure is a calculated value applied to assure

that the Market Participant engages in activities within its Total Credit Limit. The Total Potential Exposure is based on the Market Participant’s estimated cumulative financial obligation under the Tariff or otherwise to SPP. Potential Exposure to non-payment is calculated separately for each category of Market Services and Transmission Services and then summed together to obtain the amount of Total Potential Exposure. This Article addresses the calculation and use of the value for Total Potential Exposure.

5.2 Calculation of Total Potential Exposure for A Market Participant. A Market

Participant’s Total Potential Exposure shall be the sum of the potential exposure to non-payment for Energy Imbalance Market transactions and Transmission Service transactions billed pursuant to the Tariff.

5.2.1 Energy Imbalance Market Exposure (“EIME”). Potential exposure to

non-payment associated with the Energy Imbalance Market transactions that involve physical delivery of Energy is calculated under the following formula:

EIME = IMSC + CMSC + MEME

IMSC = Invoiced Market Settlement Charges (all imbalance charges that

have been invoiced but not yet paid).

CMSC = Calculated Market Settlement Charges (all daily settlement activity that has been calculated but not yet invoiced).

MEME = Maximum Estimated Market Exposure shall be the greater of:

(a) The rolling average of the last three hundred sixty five (365) days of daily settlement activity (or a lesser period of time if 365 days of settlement activity are unavailable) times the remainder of the Potential Exposure Window, or

(b) The rolling average of the last seven (7) days of daily

settlement activity (or a lesser period of time if 7 days of settlement activity are unavailable) times the remainder of the Potential Exposure Window.

Following are examples of the calculation of Energy Imbalance Market Exposure.

Deleted: (the charges incurred on the Peak Market Activity Day in the last 365 days or a lesser period of time service has been taken, multiplied by the number of days in the Potential Exposure Window).

Example of Energy Imbalance Market Exposure Calculation:

ASSUMPTIONS: CURRENT DAY IS TUESDAY, NOVEMBER 23, 2004 CUSTOMER HAS PAID PREVIOUS WEEKLY INVOICE IN FULL(NOVEMBER 12) HIGHEST POSITIVE DAILY SETTLEMENT FOR LAST 365 DAYS IS $1,000

Settlement Settlement Operating Operating Invoice Invoice Weekday Date Weekday Date Date Amount

INVOICED MARKET SETTLEMENT

CHARGES (IMSC) Mon 11/13/04 Mon 11/08/04 11/19/2004 $1,000Mon 11/14/04 Tue 11/09/04 11/19/2004 $850Mon 11/15/04 Wed 11/10/04 11/19/2004 $900Tue 11/16/04 Thu 11/11/04 11/19/2004 $750Wed 11/17/04 Fri 11/12/04 11/19/2004 -$500Thu 11/18/04 Sat 11/13/04 11/19/2004 $800Fri 11/19/04 Sun 11/14/04 11/19/2004 $900

TOTAL $3,850

CALCULATED MARKET

SETTLEMETN CHARGES (CMSC)

Mon 11/20/04 Mon 11/15/04 $850Mon 11/21/04 Tue 11/16/04 $900Mon 11/22/04 Wed 11/17/04 $800

TOTAL $2,550

MAXIMUM ESTIMATED MARKET EXPOSURE (MEME)

Tue 11/23/04 Thu 11/18/04 $1,000Wed 11/24/04 Fri 11/19/04 $1,000Thu 11/25/04 Sat 11/20/04 $1,000Fri 11/26/04 Sun 11/21/04 $1,000Sat 11/27/04 Mon 11/22/04 $1,000

Cure Period 11/23/04 $1,000 Cure Period 11/24/04 $1,000 Cure Period 11/25/04 $1,000 Cure Period 11/26/04 $1,000 TOTAL $9,000 TOTAL ENERGY MARKET IMBALANCE EXPOSURE (EIME) $15,400

5.2.2 Transmission Service Potential Exposure (“TSPE”). Potential

exposure to non-payment associated with Transmission Service transactions is calculated under the following formula:

TSPE = ITSC + CTSC + METE

ITSC = Invoiced Transmission Service Charges (all transmission service charges that have been invoiced but not yet been paid).

CTSC = Calculated Transmission Service Charges (transmission service charges that have been calculated but not yet invoiced).

METE = Maximum Estimated Transmission Exposure

An estimate of the charges for the remainder of the Potential Exposure Window.

Calculated using the value of all charges based on reserved capacity for each confirmed Transmission Service reservation from the last date included in the CTSC calculation above to the date of the calculation of Total Potential Exposure, plus the value of all charges based on confirmed reservations for the following seventy-five (75) days from the date of the calculation of Total Potential Exposure.

METE for Network Service reservations will be

calculated by taking the highest netted Network Service invoice over the last twelve (12) months (or a lesser period if Network Service has been taken for a shorter period), multiplied by 2.5.

Participants who do not execute Attachment N of the

Tariff, therefore self providing for losses, will have losses excluded from the METE calculation.

Following are examples of Transmission Service Potential Exposure.

Example of Transmission Service Potential Exposure Calculation: ASSUMPTIONS: CURRENT DAY IS TUESDAY, NOVEMBER 23, 2004 CUSTOMER HAS PAID PREVIOUS MONTHLY INVOICE IN FULL (NOVEMBER 18) HIGHEST MONTHLY SETTLEMENT FOR LAST 12 MONTHS IS $8,000

Operating Invoice

Date Amount Invoiced Transmission Service Charges

Deleted: (the highest transmission service invoice over the last 12 months, multiplied by 2.5).

(ITSC) Already paid October Charges on November 18 $0

TOTAL $0

CALCULATED TRANSMISSION

SERVICE CHARGES (CTSC)

11/1/2004 $300 11/2/2004 $350 11/3/2004 $250 11/4/2004 $300 11/5/2004 $350 11/6/2004 $250 11/7/2004 $300 11/8/2004 $350 11/9/2004 $250

11/10/2004 $300 11/11/2004 $350 11/12/2004 $250 11/13/2004 $300 11/14/2004 $350 11/15/2004 $250 11/16/2004 $300 11/17/2004 $350 11/18/2004 $250 11/19/2004 $300 11/20/2004 $350 11/21/2004 $250

TOTAL $6,300

MAXIMUM ESTIMATED TRANSMISSION

EXPOSURE (METE) $8000 x 2.5 TOTAL $20,000

TOTAL TRANSMISSION SERVICE POTENTIAL EXPOSURE

(TSPE) $26,300

5.2.3 Calculation of Total Potential Exposure for a Market Participant. A Market Participant’s Total Potential Exposure (“TPE”) shall be the sum of the potential exposure to non-payment for Energy Imbalance Market transactions and Transmission Service transactions billed pursuant to the Tariff and may be calculated using the formula:

TPE = EIME + TSPE

Example of Total Potential Exposure Calculation:

Continuing with the previous examples in 5.2.1 and 5.2.2 the calculation would be as follows:

EIME = $15,400

TSPE = $26,300

$15,400 + $26,300 = $41,700 (TPE)

5.3 Total Potential Exposure Violations.

5.3.1 Transaction Limits. At all times, the Market Participant shall maintain its

Total Potential Exposure to a value equal to or less than its Total Credit Limit. A “Total Potential Exposure Violation” occurs when a Market Participant’s Total Potential Exposure equals or exceeds its Total Credit Limit. SPP will regularly monitor each Market Participant’s use of services and associated financial obligations. If a Market Participant’s Total Potential Exposure equals or exceeds ninety percent (90%) of its Total Credit Limit, SPP shall promptly give notice to the Market Participant. Failure by SPP to give this notice shall not relieve the Market Participant of its duties under this Section.

5.3.2 Cure of Total Potential Exposure Violation. A Market Participant shall

cure a Total Potential Exposure Violation by: (i) payment to SPP of invoiced amounts to reduce the Market Participant’s Total Potential Exposure, and/or (ii) provision of Financial Security in an amount sufficient to increase the Market Participant’s Total Credit Limit, such that after making such payments of invoiced amounts and/or providing such Financial Security, the Market Participant’s Total Potential Exposure will not exceed its Total Credit Limit. The Market Participant shall have two (2) Business Days from the date of violation to cure the violation. SPP, in its sole discretion, may determine to treat any amount tendered under (i) as an increase of Financial Security under (ii) and not as a payment to SPP.

5.3.3 Failure to Cure Total Potential Exposure Violation. A failure to cure a

Total Potential Exposure Violation as required under Section 5.3.2 is a Default. In the event of such a Default, SPP has all rights under section 7 of the Tariff and all other rights and remedies in accordance with applicable law. Without prejudice to other remedies, a Market Participant that fails timely to cure a Total Potential Exposure Violation shall be suspended from requesting any future services, including all Transmission Service and Market Services, unless and until the Market Participant’s Total Potential Exposure Violation is cured.

5.4. Excess Financial Security. In the event a Market Participant has provided

additional Financial Security under Section 5.3.2 to address a Total Potential Exposure Violation, and the Market Participant’s outstanding invoiced amounts subsequently return to levels preceding that violation such that the total amount of Financial Security exceeds the amount required under this Credit Policy, the Market Participant may request return of the excess Financial Security and SPP

shall comply with the request within two (2) Business Days; provided, that if SPP determines to review the Credit Assessment for the Market Participant due to the violation, it shall not be required to respond to the request, including return of any excess Financial Security, until two (2) Business Days after completing the new Credit Assessment.

Southwest Power Pool, Inc. HUMAN RESOURCES COMMITTEE


Organizational Roster The following members represent the Human Resources Committee:

Quentin Jackson, Director Harry Dawson, OMPA Richard Spring, KCPL

Phyllis Bernard, Director Mike Palmer, Empire District Trudy Harper, Tenaska

Background SPP staff, at the request of the Human Resources Committee developed the attached Employee Performance Compensation Plan.

Analysis The Human Resources Committee engaged Towers Perrin to perform an evaluation and analysis of SPP’s employee and director compensation programs. The results of Towers Perrin’s work encouraged development of an incentive compensation plan for employees to ensure SPP remains competitive in attracting and retaining qualified personnel.

The Human Resources Committee sought input from the Strategic Planning Committee as well as the Finance Committee to aid in the design of the Employee Performance Compensation Plan. The attached plan represents the finished product which was reviewed by the Human Resources Committee at its October 6, 2005 meeting.

Recommendation The Human Resources Committee recommends approval of the Employee Performance Compensation Plan by the SPP Board of Directors with the plan becoming effective for SPP’s 2005 fiscal year.

Approved: Human Resources Committee 2 votes for, 1 abstention

October 6, 2005

Action Requested: Approve Recommendation

Human Resources Committee Employee Performance Compensation

Southwest Power Pool

Human Resources Committee July 25, 2005

Employee Performance Compensation

Background The Human Resources Committee (HRC) engaged Towers Perrin to provide a report on executive and non-executive compensation practices at electric utilities and ISO/RTOs. Towers Perrin published a report of its findings on August 31, 2004, which was utilized by the HRC to develop a new SPP employee salary structure, ultimately approved by the Board of Directors at its October 27, 2004 meeting. Towers Perrin also recommended adding short-term incentive compensation to SPP’s existing pay practices to match the practices of virtually all companies in its database with which SPP competes for talent and all ISO/RTOs. The HRC asked the Strategic Planning Committee (SPC) to suggest appropriate parameters on which to base this type of compensation. The SPC suggested three parameters for consideration: stakeholder satisfaction, system reliability and cost control. Analysis Staff evaluated many overall compensation plans. Staff is recommending a program focused on equitable pay for outstanding corporate performance rather than achievement of specific individual goals. This plan is meant to maintain the employment culture at SPP, which is highly valued by members and customers. Management believes this will result in continuity of employment and will instill employees with a sense of ownership in the company and its initiatives. This will benefit SPP’s stakeholders considering the complexities of managing volunteer relationships, regulatory and political expectations and public exposure in addition to normal operating issues. Payments under this program will be made in recognition of outstanding corporate and individual performance. Program payments are a part of overall compensation; however they are not to be viewed as an entitlement. The challenge of designing a performance compensation plan is to establish measurable quantitative and qualitative parameters that do not create disincentives to proper performance; i.e. padding budgets, withholding needed maintenance expenditures, or resisting needed organizational direction changes. Successful strategic management depends on accepting the inevitability of change, making some effort to anticipate change, and coping with changes as they occur. Performance Compensation Plan SPP officers utilized this input and an overall program structure recommended by Towers Perrin to develop a performance compensation plan for consideration by the HRC.


Purpose The performance compensation plan is designed to increase the commitment of employees to attaining corporate goals, to promote the management of outcomes, to encourage qualified and trained employees to remain with the company, and to attract new employees by emphasizing operating performance through the opportunity for added compensation beyond the base salary. Plan Management The plan will be administered by the HRC, which shall make annual recommendations to the Board of Directors with respect to annual budgeting, program funding, and plan effectiveness. The decision of the Board of Directors with respect to any questions arising as to awards for the President and interpretation of the provisions of the plan with respect to the office of the President will be final, conclusive, and binding on all parties. The decision of the President with respect to any questions arising as to awards for any employee and interpretation of the provisions of the plan with respect to any employee will be final, conclusive, and binding on all parties. Plan Payment Structure Compensation under the plan will be disbursed annually in the February 28th payroll based on corporate and individual performance for the previous calendar year. Target payouts assigned by salary grade are as follows:

Grade Target % 13 40 12 30 11 20 8-10 15 4-7 10

Target percentages will be applied to actual base salary as of December 31 of the plan year. Incentive compensation will be earned on corporate and individual performance with equal weight being given to three corporate parameters. The aggregate corporate performance will control 100% of the target percentage. The SPP Board of Directors will maintain authority to adjust the SPP President’s target percentage based on individual performance. The SPP President will maintain authority to adjust individual SPP staff member’s target percentage based on individual performance. In no instance will payout under the plan be less than zero. Eligibility All active employees as of December 31 of the Plan Year will be eligible to participate in the plan. Target percentages will be adjusted based on tenure of employment during the year (i.e. an employee beginning employment on July 1 would be eligible for 50% of the target percentage). Employees retiring, passing away or claiming disability status during the Plan Year will be eligible for benefits adjusted based upon the tenure of active employment during the Plan Year should the Company meet its plan targets. Employees terminating their employment with the Company during a plan year, either voluntarily (excluding retirement) or involuntarily, are not eligible for benefits under the Plan.


Cost Control Parameter Adjustments (33% weighting) Annually, the SPP Finance Committee will establish a “foundation budget” including all expected operating expenses not directly identified or affiliated with significant projects or initiatives. Actual aggregate expenses for the fiscal year associated with “foundation budget” items will be divided by the total “foundation budget” to determine the measure. Actual Foundation/Foundation Budget Funding as % of Target >115% -100% 115 %<X>110 0 110 %<X>105 50 105 %<X>95 100 95<X>85 125 < 85 150 Stakeholder Satisfaction Parameter Adjustments (33% weighting) Staff is recommending the use of an online method for measuring customer satisfaction. Retail software is available to create, distribute, and calculate a survey, which can be sent to members, customers, and other stakeholders via email. Software features include: automatically generated reports to assist with real-time results analysis; ability to export survey data to Excel; and the option to keep private or share survey results by providing a specific web link to others. Respondent anonymity can be provided; however, one option allows respondent tracking so a reminder note can be generated to the non-respondents. Overall Survey Results Funding as % of Target Very Dissatisfied (avg <2.5) -100% Somewhat Dissatisfied (2.5<avg<3.0) 0 Satisfied (3.0<avg<3.8) 70 Very Satisfied (3.8<avg<4.5) 100 Extremely Satisfied (avg>4.5) 150 Reliability Parameter Adjustments (34% weighting) Systems Availability, excludes scheduled maintenance (36% weighting) OASIS, RTOSS, ICPP Availability Funding as % of Target All under 99.5% -100% Two under 99.5% 0 One under 99.5% 25 One under 99.8% 75 One under 99.95% 100 All 99.99% or greater 150 Transmission System Reliability (32% weighting for each metric) NERC RC Violations Funding as % of Target


>1 -100% 1 0 0 100

Transmission Assessment Availability Funding as % of Target <99.5% DA and 90% SE -100% 99.5% DA and 90% SE 10 99.8%DA and 95%SE 100 100% DA and 95% SE 150 Corporate Modifier A factor set by the Board of Directors to be applied to the sum of the three parameters above in consideration of corporate conditions not specifically accounted for in the three parameters above. The modifer can range from -20% to plus 20%. Allocation to Individual Participants The above methodology establishes the potential pool of monies to be allocated to individual SPP employees based upon that employee’s contribution to SPPs success in achieving its goals. The SPP Board of Directors will allocate performance compensation payment for the SPP President. The SPP President will allocate performance compensation payments to the SPP staff. Example calculation SPP achieved the following results for fiscal year 200#:

1) actual foundation expenditures equal 105% of target 2) stakeholder satisfaction survey indicated “satisfied” rating of 3.75 3) OASIS availability equals 99.99% 4) RTOSS availability equals 99.4% 5) ICCP availability equals 99.8% 6) Zero NERC RC violations 7) 100% day ahead and 95% state estimator availability

Calculation of SPP plan metrics is as follows:

a) Cost Control: This component has a 33% weighting. From the table the target percentage is 100% therefore:

0.33 x 1.00 = 0.33 b) Stakeholder satisfaction has a 33% weighting. From the table the target

percentage is 70%, therefore: 0.33 x 0.70 = 0.231

c) Reliability parameters have an overall 34% weighting. System availability from the table the target percentage is 25% * .36 = 0.09, NERC RC violations have a 32% weighting. From the table the target percentage is 100%, therefore: 0.32 x 1.00 = 0.32


Transmission Reliability has a 32% weighting. From the table the target percentage is 105%, therefore: 0.32 x 1. 50 = 0.48 Total reliability parameters equals the sum of the individual weighted parameters multiplied by the reliability parameter weighting of 34%as follows: (0.09 + 0.320 + 0.48) * 0.34 = 0.3026

SPP overall performance is obtained by adding together the results from the individual components of the plan: Cost Control 0.333 Customer Satisfaction 0.231 Reliability 0.303 0.867 or 86.7% bonus target The Performance Compensation Target is then presented to the Board of Directors for application of the corporate modifier. In this example, let’s assume SPP missed its budget targets due to implementation of unbudgeted initiatives approved by the stakeholders. The Board felt the Performance Compensation Target was too low and applied a +10% corporate modifier: 0.867 x 1.10 = 0.953 or 95.3% The Performance Compensation Target, together with the funding targets by grade and SPP’s year-end annualized salaries by grade are utilized to compute the available pool of performance compensation funding per the table illustrated below: Funding Adj. Funding Grades Target PCT Target Salaries Pool 13 40% 95.3% 38.1% $300,000 $114,300 12 30% 95.3% 28.6% $970,000 $277,420 11 20% 95.3% 19.1% $964,500 $184,,220 8-10 15% 95.3% 14.3% $6,101,590 $872,527 4-7 10% 95.3% 9.5% $4,325,500 $410,923 Total Pool $12,661,590 $1,809,390 Cost The Performance Compensation pool is expected to average approximately 15% of SPP’s year end annualized salaries. Funding targets for the 2005 plan year will be set at 50% of the targets outlined in this document in recognition of the late year roll-out of the plan.


Recommendation SPP Staff recommends to the HRC approval of the proposed incentive compensation plan for immediate implementation with the first opportunity for payout under the program being February 2006.

Southwest Power Pool, Inc. STRATEGIC PLANNING COMMITTEE


Bylaws Revision - Waiver of Annual Membership Fee

Background In an order issued October 7, the Federal Energy Regulatory Commission (the Commission) directed SPP to amend its Bylaws to include provisions for certain classes of membership to request a waiver of annual membership fees associated, specifically public interest groups, including large and small retail customer members. Analysis SPP had previously amended its Bylaws to waive withdrawal obligations for these sectors of the membership since that obligation had been raised by some prospective members in these categories as a deterrent to joining SPP. The requirement of payment of an annual membership fee was retained. In its October 7 order, the Commission directed SPP again to develop a process whereby a member in one of the named sectors could request a waiver of the annual membership fee (emphasis added). The Commission also determined that the waiver of withdrawal obligations for some sectors of the membership is “unduly discriminatory” and rejected it. Proposed revisions to the Bylaws are offered for consideration and discussion. Recommendation Approval of Bylaws revisions to be recommended to the Board of Directors for action, following the required notice period to the Membership (30 days).

Approved: Strategic Planning Committee October 13, 2005

Board of Directors

Action Requested: Approval

PROPOSED REVISION SPP Bylaws

October 2005 8.2 Annual Membership Fee

All SPP Members will be subject to an annual membership fee to recover the costs

incurred by SPP related to maintaining reliability criteria and related compliance.

Members without “Net Energy for Load” within SPP will pay an annual membership fee

of $6,000, or other amount established by the Board of Directors. The Board of Directors

shall determine the annual membership fee for the upcoming year in advance of the last

meeting of Members in a calendar year. Those Members serving load will be subject to a

fee based on their annual Net Energy for Load within SPP for the preceding year.

Membership fees are not subject to refund. Members of the Alternative Power/Public

Interest, Large Retail Customer, and Small Retail Customer sectors of the membership

may seek waiver of the annual membership fee. The request for waiver must be directed

to the President in writing 90 days in advance of the start of each fiscal year.

Southwest Power Pool, Inc. MARKETS AND OPERATIONS POLICY COMMITTEE

Recommendation to the Board of Directors/Members Committee October 25, 2005

Organizational Roster The following members represent the Operating Reliability Working Group:

Gerry Burrows, KCP&L Bob Cochran, SPS Allen Klassen, Westar Pete Kuebeck, OG&E Steve Massey, Westar

Scott Moore, AEP (Chair) Maxwell Reid, CLECO Keith Sugg, AECC Jim Thompson, Constellation Energy Noman Williams, SECI

The following stakeholders participated in group discussions:

Dan Boezio, AEP Bob Cochran, SPS Mike Crouch, WFEC Will Franklin, Entergy Mike Gammon, KCP&L Steve Hillman, WPEK Allen Klassen, Westar Pete Kuebeck, OG&E

John Mason, MPS Stan Mason, SPA Steve Massey, Westar Jim McAvoy, OG&E Scott Moore, AEP Bill Nolte, SECI Bary Warren, EDE Noman Williams, SECI

Background The Operating Reliability Working Group (ORWG) charged the Coordinated Black Start Task Force (CBSTF) with several tasks on March 25, 2004. One of these tasks was to recommend changes to the SPP Criteria with regards to the following:

a) Formalized coordination between neighboring entities

b) Guidelines and/or criteria regarding verification of black start capability

c) Guidelines and/or criteria for modification of black start plans

Analysis The CBSTF reviewed Criteria 9 in light of NERC Version 0 Standards and the ORWG’s charge. Through this process, the CBSTF made the necessary modifications to Criteria 9 and presented those changes to the ORWG at its September 2005 meeting. The ORWG reviewed the proposed language for Criteria 9, made slight modifications to that language and approved the Criteria 9 changes as modified.

Recommendation

The MOPC recommends the Board of Directors approve the proposed revisions to SPP Criteria 9.

Approved: Operating Reliability Working Group September 7, 2005 Passed Unopposed

Markets and Operations Policy Committee October 12, 2005

Passed Unopposed

Action Requested: Approve Recommendation

Southwest Power Pool Criteria

9-1 May 7, 2002

9.0 BLACK START This document provides general guidelines to be followed in the event of a partial or

complete collapse of the SPP bulk electric system. Quick implementation of each

Balancing Authority/Transmission Operator restoration plan compiled according to this

Criteria and the NERC Reliability Standards shall facilitate coordination between

member Balancing Authorities/Transmission Operators and the SPP Reliability

Coordinator and insure the earliest possible restoration of the electric system. It is

impossible to predict all the possible combinations of system problems that may occur

after a major electric system failure. It is therefore the responsibility of system operators

to restore the electric system applying the general guidelines outlined in this document

and in their respective detailed black start plans. Strict adherence to other SPP Criteria

is also necessary for a prompt restoration of the electric system. Mutual assistance

between members Balancing Authorities/Transmission Operators is highly encouraged.

This assistance may include the sharing of black start units. The SPP Reliability

Coordinator shall take an active role during electric system restoration as outlined in this

Criteria. Each Balancing Authority/Transmission Operator shall have a readily accessible

and sufficiently detailed, current restoration plan to assist in an orderly restoration.

Restoration shall be aided by communicating to neighboring Balancing

Authorities/Transmission Operators and the SPP Reliability Coordinator an accurate

assessment of the network conditions throughout the restoration process.

Communication shall be established between neighboring operation centers, power

plants and the SPP. Mutual assistance and cooperation are essential during restoration

activities to avoid reoccurrence of a partial or complete electric system collapse.

9.1 Responsibilities

SPP shall develop and maintain a Regional Black Start Capability Plan and a Regional

Restoration Plan in accordance with NERC Reliability Standards. The Regional Black

Start Capability Plan and Regional Restoration Plan will be reviewed on an annual basis

to ensure the plans maintain effectiveness and accuracy. It is the responsibility of SPP

Staff to review and update the plans as required and to bring such proposed updates to

the Operating Reliability Working Group (ORWG) for their review and approval. The

annual review and any proposed updates are to be submitted to the ORWG no later than

April 1.

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9-2 May 7, 2002

9.1.1 Members Each Balancing Authority/Transmission Operator shall develop and maintain a detailed

internal black start plan. Each Balancing Authority/Transmission Operator shall review

their black start plan annually and shall provide SPP with the latest version of their black

start plan whenever changes are made or as requested by SPP Staff. Transmission

Operators shall prepare a plan in cooperation with their responsible Balancing Authority

designed to assist and coordinate with the Balancing Authority’s plan. This applies to

cogeneration facilities and independent power producers. A copy of this plan shall be on

file at the SPP office. Black start plans shall be verified by a minimum of simulation

testing, although actual physical testing is highly encouraged where feasible. Members

shall report any testing activities of black start plans to the ORWG.

Balancing Authorities and Transmission Operators shall train appropriate personnel in

the implementation and execution of their black start plan.

In the event of an electric system collapse, each Balancing Authority/Transmission

Operator shall use the following items as guiding principles for the restoration process.

a. Provide assistance to any and all SPP Balancing Authorities and

Transmission Operators as abilities allow, with priority given to the

restoration of inter-system bulk electric system ties

b. Make adjustments to interchange schedules between affected areas as

necessary to facilitate restoration efforts

c. Take immediate steps to initiate internal restoration plans

d. Supply neighboring Balancing Authorities/Transmission Operators and the

SPP Reliability Coordinator with information on network status

e. Coordinate with neighbors the re-connection of Balancing Areas and/or

islands.

f. If it becomes apparent that the emergency is of regional magnitude, the

focus of restoration action shall shift from individual Balancing Area

priorities to bulk network priorities. Priority to a neighboring Balancing

Authority/Transmission Operator load may be necessary in order to benefit

the overall strength of the bulk electric system. As generation and

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9-3 May 7, 2002

transmission facilities become available, systematic restoration of network

load shall be initiated with respect to priorities

g. Generation should be made available to all regional utilities for system and

customer load restoration as recommended by the SPP Reliability

Coordinator

9.1.2 SPP Reliability Coordinator The SPP Reliability Coordinator shall be familiar with each Balancing

Authority/Transmission Operator black start plan that is on file. In the event of a failure

of the bulk electric system, the SPP Reliability Coordinator personnel shall take the

following action.

a. The SPP Reliability Coordinator has the authority to temporarily suspend

normal energy scheduling practices and to restore those practices once an

operating emergency has been mitigated.

b. The SPP Reliability Coordinator should recommend sharing of generation

available to all regional utilities for system and customer load restoration.

c. Maintain continuous surveillance of the status of the networks of all member

Balancing Authorities (refer to section 9.4 for information required).

d. Act as a central information collection and dissemination point for Balancing

Authorities/Transmission Operators.

e. Communicate with other regional offices, NERC and the Federal Emergency

Management Administration.

f. Communicate/recommend the need for assistance to appropriate Balancing

Authorities/Transmission Operators.

g. The SPP Reliability Coordinator shall approve, communicate, and

coordinate the re-synchronizing of major system islands or synchronizing

points..

h. The SPP Reliability Coordinator shall expect notification of Balancing

Authority status. It is necessary that this information be recorded and

shared with all Balancing Authorities/Transmission Operators. Based on this

information, the SPP Reliability Coordinator shall immediately assess

electric system conditions and status of communication facilities and inform

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9-4 May 7, 2002

all Balancing Authorities of the extent of the blackout (refer to section 9.4 for

information required).

9.2 Elements of Balancing Authority/Transmission Operator Black Start Plans Each Balancing Authority/Transmission Operator shall maintain a black start plan that is

consistent with the NERC Reliability Standards. All plans and procedures shall be

readily available to system operators, plant operators and the SPP Office. System

operators shall review these documents on a regular basis. It is suggested that

Balancing Authority/Transmission Operator black start plans include the following

elements.

a. Philosophies and strategies for Balancing Area restart

b. Identification of the relationships and responsibilities of the personnel

necessary to the restoration

c. Identification of black start resources including generating unit resources,

sufficient fuel resources, transmission corridors or paths, communication

resources and power supplies, mutual assistance arrangements

d. Contingency plans for failed resources

e. Identification of critical load requirements

f. Identification of special equipment requirements

g. Provisions for training and documentation of training for personnel

h. Provisions for simulating and where practical, actual testing and

verification of the resources and procedures

i. General instructions and guidelines for system operators, plant operators,

communications personnel, and transmission and distribution personnel

j. Provisions for public information

k. Synchronization Guidelines including operating instructions and

procedures for synchronizing areas as may be dictated in the restoration

plan

l. The functions to be coordinated with neighboring Reliability Coordinators,

Balancing Authorities, and Transmission Operators

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9-5 May 7, 2002

m. Notifications to neighboring Reliability Coordinators, Balancing

Authorities, Transmission Operators, and other operating entities as

phases of the restoration plan are implemented

Appendix 4 contains a list of items to be considered in the restoration process that may

be used in the development or review of black start plans. 9.3 Restoration Priorities

The following actions for system restoration shall be considered by each Balancing

Authority and assigned proper sequence and priority.

a. Stabilization of generating units

b. Restoration of inter-system and intra-system bulk electric system ties

c. Restoration and maintenance of intra- and inter-system communication

facilities and networks

d. Assessment of Balancing Area condition and SPP electric system

condition

e. Contact with public information agencies (Emergency Broadcasting

System) to request the broadcasting of pre-distributed appeals and

instructions

f. Restoration of units with black start capability

g. Providing service to critical electric system facilities

h. Connection of islands taking care to avoid reoccurrence of a partial or

complete system collapse and equipment damage

i. Restoration of service to critical customer loads

j. Restore service to the remaining customers

9.4 Information Communication

Reliable communication between Balancing Authorities/Transmission Operators and

SPP Reliability Coordinator will be the key to a safe and timely restoration following a

collapse of the SPP network. As part of the initial assessment after a partial or complete

system blackout, communication facilities shall be tested and verified. System operators

shall establish communication within their area with special emphasis given to power

plants and neighboring members. To expedite the recovery process, the SPP

Emergency Communication Network (satellite phones) shall be used to convey

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9-6 May 7, 2002

appropriate information to members. Balancing Authorities/Transmission Operators shall be prepared to communicate their status once an hour, or when polled by the SPP Reliability Coordinator Only after voice communication paths have been

established shall efforts be directed to re-establishing data communication paths.

System status conditions to be surveyed include but are not limited to the following

items.

a. Areas of the electric system that are de-energized

b. Areas of the electric system that are functioning

c. Amount of generation and generating reserve available in functioning

areas

d. Power plant availability and time required to restart

e. Status of transmission breakers and sectionalizing equipment along

critical transmission corridors, and at power plants

f. Status of transmission breakers and sectionalizing equipment at tie points

to other areas

g. Status of fuel supply from external suppliers

h. Under-frequency relay operation

i. Relay flags associated with circuits tripped by protective relays

j. Status of communication systems


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