Regular Meeting · 1/24/2011 · Board of Directors PO Box 1 Johnson City, TX 78636 Regular Meeting ~ Agenda Call PEC Toll Free 1-888- 554-4732 Monday, January 24, …

Board of Directors PO Box 1

Johnson City, TX 78636

Regular Meeting www.pec.coop

~ Agenda Call PEC Toll Free1-888- 554-4732

Monday, January 24, 2011 10:00 AM PEC Headquarters Auditorium

Board of Directors Page 1 Revised 1/20/2011

1. Call to Order and Roll Call

10:00 AM Meeting called to order on January 24, 2011 at PEC Headquarters Auditorium, 201 South Avenue F, Johnson City, TX.

2. Employee/Director Recognitions for Approval

A. (Resolution (ID # 1504)) Retirement of Gladys M. Wood, after 26 years of service.

3. Minutes Approval

A. Monday, December 20, 2010 Regular Meeting

B. Tuesday, January 04, 2011 Special Meeting

4. Items from Members

5. Executive Session

A. Competitive Matters:

B. Contracts:

C. Legal Matters:

1. Whistleblower Administrator Update

2. Litigation Update, Including Threatened Litigation

3. Gunter Litigation

4. Annual Review of Conflicts of Interest Policy Requirements

5. Bylaws and Director Qualifications

D. Personnel Matters:

E. Real Estate Matters:

6. 1:00 PM - Reconvene to Regular Meeting

Regular Meeting Agenda January 24, 2011


7. Items From Members

8. Items From Directors

Larry Landaker

A. Annual Submission of Conflict of Interest Certification and Disclosure Form

B. Director Qualifications

C. Strategic Issues Member Feedback

D. Strategic Issues Discussion

Chris Perry

E. Annual Submission of Conflict of Interest Certification and Disclosure Form

F. Director Qualifications

Cristi Clement

G. Annual Submission of Conflict of Interest Certification and Disclosure Form

Kathy Scanlon

H. Annual Submission of Conflict of Interest Certification and Disclosure Form

Ross Fischer

I. Annual Submission of Conflict of Interest Certification and Disclosure Form

J. Jurisdiction, Authority and Processes Relating to Committees of the Board

K. Methods for Increasing Member Feedback

L. Rewards and Recognition Luncheons

Patrick Cox

M. Annual Submission of Conflict of Interest Certification and Disclosure Form

9. Items From Executive Session

10. Report on Monthly Safety Performance

A. January 2011 BOD Safety Report

11. Report on Monthly Power Supply

A. LCRA Resource Planning



12. Report on Monthly Operations

A. Monthly Operations Report

13. 2011 Budget Presentation

A. (Resolution (ID # 1505)) 2011 Budget Presentation

14. Informational Items

A. Monthly Informational Items

Total Active Accounts 236,997 (net increase 175)

Total Memberships 199,542 (net increase 140)

Purchase Orders $ 1,859,534.61

Write-off of Uncollectible Accounts $ 195,864.02

Non-electrical Bad Debt Write-off $ 0.00

Power Bill (unaudited)

394,924,060 kWh Current month/yr $ 23,811,305.16 (includes LCRA & AEP)

435,434,705 kWh Previous year $ 28,409,290.45 (includes LCRA & AEP)

15. Chief Financial Officer

A. CFO - Monthly Reports

1. Reports on December 2010 Monthly Financials

B. CFO - Action Items/Other Items

16. Audit Committee

A. AC - Reports

1. Audit Committee Minutes

B. AC - Action Items/Other Items

1. (Resolution (ID # 1490)) Authority of Audit Committee Chair to Execute Certain Contracts

17. Compensation Committee

A. CC - Reports

1. Compensation Committee Minutes November 2010

B. CC - Action Items/Other Items



18. Energy Committee

A. EC - Reports

B. EC - Action Items/Other Items

1. (Resolution (ID # 1491)) Conservation Programs

19. Executive Search Committee

A. ESC - Reports

B. ESC - Action Items/Other Items

20. Financial Strategies, Contracts, and Budget Committee.

A. FSCB - Reports

B. FSCB - Action Items/Other Items

21. Governance, Bylaws and Legal Committee.

A. GBL - Reports

1. GBL Minutes of 12-3-10

B. GBL - Action Items/Other Items

1. (Resolution (ID # 1488)) Amendment to Delegation of Authority Regarding General Counsel

22. Chief Executive Officer

A. CEO - Reports

1. Presentation on Strategic Initiatives 2011 - 2013

2. Briefing on recent Emergency Operations Plan

3. Process for Legislative Matters and Legislative Report

B. CEO - Action Items/Other Items

1. (Resolution (ID # 1507)) TEC 2011 Annual Membership Dues

C. Announcements



23. Future Items for Board Consideration

24. Future Meetings

A. Announce February Regular Board Meeting scheduled for 10 am on February 21, 2010 at the PEC Headquarters.

25. Adjourn

Board of Directors Meeting: 01/24/11 10:00 AM

PO Box 1Johnson City, TX 78636

Sponsors:

RESOLUTION (ID # 1504) DOC ID: 1504

Updated: 1/18/2011 7:58 PM by Aisha N Hagen Page 1

Subject: Gladys M. Wood Retirement Resolution

Submitted By: Theresa Owens

Department: Human Resources

Background:

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Pedernales Electric Cooperative, Inc.Regular MeetingJanuary 24, 2011

RESOLUTION (ID # 1504)

Retirement of Gladys M. Wood, after 26 years of service.

The State of TexasCounty of Blanco

Whereas, Gladys M. Wood will retire from her employment with Pedernales Electric Cooperative, Inc. after faithfully and competently serving the members of PEC in various capacities for 26 years; and,

Whereas, Gladys M. Wood has successfully applied her considerable energy, experience, and knowledge to providing the Members of Pedernales Electric Cooperative, Inc. with reliable electric service; and,

Whereas, in the course of her employment, Gladys M. Wood has earned the friendship and respect of the Directors, Employees, and Members of Pedernales Electric Cooperative, Inc. for whom and with whom she has worked; and,

Whereas, Gladys M. Wood’s experience and willingness to serve will be sorely missedby the Members, Employees, and Board of Directors of Pedernales Electric Cooperative, Inc.; and,

Whereas, the Board of Directors of Pedernales Electric Cooperative, Inc. of Johnson City, Texas, thinks it fit and proper that a Resolution be passed and spread upon the minutes recognizing the contributions made by Gladys M. Wood;

Now, Therefore, be it resolved by the Board of Directors of Pedernales Electric Cooperative, Inc. of Johnson City, Texas, that all Members, Employees, Officers, and Directors of Pedernales Electric Cooperative, Inc. hereby express their great appreciation to Gladys M. Wood and their gratitude for the incalculable service rendered by Gladys M. Wood to her fellow employees and friends of Pedernales Electric Cooperative, Inc., and,

Be It Further Resolved that this resolution be delivered to Gladys M. Wood.

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Regular Meeting www.pec.coop

~ Minutes ~ Call PEC Toll Free

1-888- 554-4732

Monday, December 20, 2010 10:00 AM PEC Headquarters Auditorium


1. Call to Order and Roll Call

President Larry Landaker addressed the audience and informed them that there is an exceptionally heavy agenda and the meeting may be longer than usual. The Board appreciates everyone's understanding.

10:00 AM Meeting called to order on December 20, 2010 at PEC Headquarters Auditorium, 201 South Avenue F, Johnson City, TX.

Attendee Name Title Status ArrivedCristi Clement District 1 Director/Secretary-Treasurer Present 10:00 AMKathryn Scanlon District 3 Director Present 10:00 AMChris Perry District 4 Director/Vice President Present 10:00 AMRoss Fischer District 5 Director Present 10:00 AMLarry Landaker District 6 Director/President Present 10:00 AMDr. Patrick Cox District 7 Director Present 10:00 AM

2. Employee/Director Recognitions for Approval

The Board unanimously approved the resolutions without objection.

A. (Resolution (ID # 1440)) Retirement of Melinda L. Armbruster, after 27 years of service.

B. (Resolution (ID # 1441)) Retirement of Shirley A. Runyon, after 26 years of service.

President Larry Landaker informed the audience that we would move from agenda item # 2 (Employee/Director Recognitions) to agenda item # 5 (LCRA CDPP Presentations).

3. Minutes Approval

A. Monday, November 15, 2010


During the morning session of the Regular Board meeting, the following members spoke on topics including but not limited to the following:

a. Esperanza Holford and Cindy Sultemeier - Representatives from Post Oak Community School House, Blanco County, asked for consideration of the service availability monthly fee since the fee usually exceeds their monthly usage.

b. Milton Hawkins - Asked the Board to consider forfeiture of Bennie Fuelberg's pension plan payments. In addition, he encouraged the Board to seek all restitution due to the member owners from Bennie Fuelberg. He also expressed his concerns on easements and rights of way, employees' defined benefit plan, litigation, and the Strategic Plan.

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Regular Meeting Minutes December 20, 2010


5. LCRA CDPP Presentations

A. LCRA Community Development Partnership Program Grant Check Presentations

President Larry Landaker informed the audience that we would move from agenda item # 2 (Employee/Director Recognitions) to agenda item # 5 (LCRA CDPP Presentations). Tom Martine, the Blanco area representative on the LCRA Board of Directors was also present. President Landaker gave a description of the program, eligibility requirements, and acknowledged the grant recipients as noted below.

About the ProgramThe Community Development Partnership Program (CDPP) provides grants to communities in LCRA’s service area for capital projects that support community and economic development and benefit the public.

Eligibility RequirementsVolunteer fire departments, emergency medical services, school districts, libraries, civic groups, local governments, and nonprofit organizations may apply for the grants.

Projects must be in LCRA’s electric or water service area. They must be for capital improvements and remain open and accessible to the public for the life of the completed project.

The maximum CDPP grant is $25,000, with an average grant being $17,000. Emphasis is placed on projects that include energy efficiency, water conservation, or household hazardous waste facilities.

Grants of $5,000 or more require a minimum 20 percent match by the grant recipient of the total project cost.

Today’s RecipientsThe number of grant applications typically exceeds available funding; because of this, and PEC’s commitment to the community, we have a team of individuals in our Community Relations Department that work with organizations on their grant applications to LCRA. We are thrilled to have with us today representatives from six groups that received our assistance and were awarded funds through this very worthwhile program.

Organization Project Description Grant Amount

Bergheim VFD Purchase four sets of self-contained breathing apparatus

$12,456

Blanco Volunteer Ambulance Corps

Purchase new stretchers and other emergency equipment for ambulances

$8,772

Bulverde-Spring Branch EMS Purchase emergency equipment for ambulances

$20,550

Friends of Spicewood Community Library

Construct an addition to the existing Spicewood Community Library

$25,000

Highland Arts Guild, Inc. Replace overhead lighting in the existing building for improved efficiency

$4,900

Old Spicewood Community School House

Complete the interior renovations of the Old Spicewood Community School House

$25,000


The Board convened to Executive Session at 10:25 AM.

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A. Contracts:

(Resolution 2010-125) Transmission Line Construction Agreement

B. Personnel Matters:

Executive Search Update

(Resolution 2010-126) Approval of Wage & Salary Policy, including Wage Scale

(Resolution 2010-127) Employee Defined Benefit Plan Third Amendment

(Resolution 2010-128) 2010 Defined Benefit Plan Funding

C. Discussion of Strategic Plan Draft:

1. Executive Session items identified as competitive matters, real estate matters, security matters, personnel matters, and legal matters.

D. Legal Matters:

1. Whistleblower Administrator Update

2. Litigation Update, Including Threatened Litigation

3. Legal Analysis of Easements and Rights of Way

4. Criminal Prosecution of Former General Manager


E. Competitive Matters

F. Real Estate Matters

7. 1:00 PM - Reconvene to Regular Meeting

The Board reconvened from Executive Session at 2:35 PM.

8. Items From Members

During the afternoon session of the Regular Board meeting, the following members spoke on topics including but not limited to the following:

a. Merle Moden - Referenced letter he submitted to the Cooperative about excessive expenditures. He gave a brief comparison of expenditures to other cooperatives and asked the

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Board to begin a process that will put us in a peer group median.

b. Robert Dedman - Urged the Board to get an attorney, on behalf of the membership, for the prosecution of Bennie Fuelberg. He encouraged the Board to ask Judge Mills to secure the maximum restitution and jail time allowed to benefit the membership. Resolution numbers 1487, 1489, and 1491 do not include language in the Board package and wants to know why. He suggested that this afternoon's open session be held the next morning to avoid leaving the members waiting due to the heavy agenda.

c. Paul Langston - Inquired on charitable donations and programs, Bennie Fuelberg trial, and $300,000 in uncollectibles. He also mentioned that he believes that the Cooperative is giving away free power to old friends.

d. Ernest Altgelt - Asked the Board if they were making any effort in getting all the money back from Bennie Fuelberg. He also mentioned that the Cooperative should ask for political contributions that were given away by Bennie Fuelberg.

9. Items From Executive Session

1. (Resolution 2010-125) Transmission Line Construction Agreement

RESULT: ADOPTED [UNANIMOUS]

MOVER: Dr. Patrick Cox, District 7 Director

SECONDER: Ross Fischer, District 5 Director

AYES: Clement, Scanlon, Perry, Fischer, Landaker, Cox

2. Victim Impact Statement

RESOLVED BY THE BOARD OF DIRECTORS OF THE COOPERATIVE, that the Acting General Counsel of the Cooperative prepare and file a victim impact statement with the Court considering the case of State of Texas v. Bennie Fuelberg; and

BE IT FURTHER RESOLVED, that said statement shall reflect financial and other damage to the Cooperative and its membership stemming from the activities of the defendant, and shall describe the limited alternative avenues of legal redress for recouping such losses; and

BE IT FURTHER RESOLVED, that the Acting General Manager or his designee is authorized to take such actions as needed to implement this resolution.





3. Executive Search Update

RESOLVED BY THE BOARD OF DIRECTORS OF THE COOPERATIVE, that the Board of Directors meet in a Special Board Meeting, as authorized by Article IV, Section 2 of the PEC Bylaws, at 10 a.m. Tuesday, January 4, 2011 at the E. Babe Smith Headquarters Building of the Cooperative in Blanco County, Texas; and

BE IT FURTHER RESOLVED, that the purpose of said meeting shall be to receive and

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discuss matters currently before the Executive Search Committee of the Board, and such other business as may come before the Board with proper notice given; and




SECONDER: Kathryn Scanlon, District 3 Director


4. Key Performance Indicators

RESOLVED BY THE BOARD OF DIRECTORS OF THE COOPERATIVE, that payments be made to employees of Pedernales Electric Cooperative, Inc. in recognition of company achievement on Key Performance Indicators, at the following levels:

• Gold Level for Safety - OSHA Recordable Injury Rate• Platinum Level for Safety - Experience Modification Rate• Platinum Level for Operational - SAIDI• Silver Level for Customer Service - JD Power Overall Customer

Satisfaction Rating (All Utilities Quarterly Average)• Platinum Level for Customer Service - JD Power Overall Customer

Service Rating (All Utilities Quarterly Average)• Platinum Level for Financial - Total Controllable Costs per Meter• Platinum Level for Financial - Equity Ratio• Gold Level - Financial - Achievement of CIP Total Budget

BE IT FURTHER RESOLVED, that the payment shall be made, according to the following formula:

A payment of 5.5% percent of the base pay and overtime of each employee during the period from November 1, 2009 through October 31, 2010, paid to any person employed by PEC on the date of the payment and in no event shall exceed $7,500 to any employee,



MOVER: Ross Fischer, District 5 Director



5. (Resolution 2010-126) Approval of Wage & Salary Policy, including Wage Scale

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RESULT: ADOPTED [4 TO 2]



AYES: Kathryn Scanlon, Chris Perry, Ross Fischer, Dr. Patrick Cox

NAYS: Cristi Clement, Larry Landaker

6. (Resolution 2010-127) Employee Defined Benefit Plan Third Amendment


MOVER: Kathryn Scanlon, District 3 Director

SECONDER: Dr. Patrick Cox, District 7 Director


7. (Resolution 2010-128) 2010 Defined Benefit Plan Funding



SECONDER: Cristi Clement, District 1 Director/Secretary-Treasurer


8. (Resolution 2010-129) PEC Strategic Plan

The Board voted on the proposed PEC Strategic Issues and made amendments to item # 5 Communication Issues and item # 7 Member Services Issues as attached in final document, "PEC Strategic Issues." The Board also voted to post the document on the Cooperative's website for member input.


MOVER: Larry Landaker, District 6 Director/President



10. Report on Monthly Safety Performance

Deputy General Manager, Paul Hilgers gave an update on Safety and mentioned that the position for the Safety Manager has been posted internally and externally.

A. December Safety Report

11. Report on Monthly Operations

System Engineering Manager, Robert Peterson presented the monthly operations report. He gave a status update on the outage that occurred last Monday, December 13, in Dripping Springs. He reported that the cause may have been slag in the wire and that we have a program which will identify these types of problems.

President Larry Landaker informed the audience that we would move to agenda item # 15 (Report from Power Supply Manager) after agenda item # 11 (Report on Monthly Operations).

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A. Monthly Operations Report

12. Informational Items

A. Monthly Informational Items

Total Active Accounts 236,822 (net increase 381)

Total Memberships 199,402 (net increase -26)

Purchase Orders $ 7,130,957.13

Write-off of Uncollectible Accounts $ 300,264.30

Non-electrical Bad Debt Write-off $ 0.00

Power Bill (unaudited)

352,406,593 kWh Current month/yr $ 21,986,037.40 (includes LCRA & AEP)

322,115,960 kWh Previous year $ 21,640,520.04 (includes LCRA & AEP)

13. Chief Financial Officer

Chief Financial Officer, Mike Vollmer reported on the monthly financials, gross margins, debt service coverage, operating revenues and expenses forecast, budget to actual, and invoices paid over $10,000.

The Board recessed to break at 3:51 PM and reconvened from break at 3:59 PM.

A. CFO - Monthly Reports

1. Reports on November 2010 Monthly Financials

B. CFO - Action Items/Other Items

14. Items From Directors

Larry Landaker

A. (Resolution 2010-118) 2011 NRECA Annual and Regional Meeting Voting Delegates



SECONDER: Chris Perry, District 4 Director/Vice President


Cristi Clement

B. (Resolution 2010-119) Bylaw Amendment: Easements/Rights of Way

Director Cristi Clement moved to approve the resolution. Director Larry Landaker seconded the motion.

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PROPOSED REVISION TO ART 1, SECTION 9

Section 9. Grant of Easements, Rights-of-Way or Licenses.

In consideration of the furnishing of Electric Service, upon request of the Cooperative, a Member shall: (1) provide the Cooperative reasonable access to or reasonable use of real property in which the Member holds an interest sufficient to grant such access or use ("Member Property"), and (2) pursuant to law and any reasonable terms and conditions specified by the Cooperative, and without compensation from the Cooperative, grant or convey to the Cooperative a written easement, right-of-way or license for reasonable use of Member Property as specified by the Cooperative for the purpose of providing Electric Service to the Member, and (3) when the use of Member Property is necessary for the provision of Electric Service to another Member, negotiate in good faith with the Cooperative for a written easement, right-of-way or license for the purpose of providing Electric Service to that Member.

NOTE:There may also be a need to make mention of this issue in Art 1, Section 1, Membership Procedures and the related business rules concerning obtaining the member’s consent to this condition at time of application for service.

Director Patrick Cox moved to refer the resolution to the Governance, Bylaws, and Legal Committee for review and re-submission at the February 2011 Board meeting. Director Chris Perry seconded the amendment. Directors voted unanimously on the amendment.

Kathy Scanlon

Ross Fischer

C. 1497: Internal and External Communications Policy

Director Ross Fischer moved to refer the Internal and External Communications Policy to the Governance, Bylaws, and Legal Committee for further review.





Patrick Cox

D. (Resolution (ID # 1489)) Installment Plan for Deposits

With no objection the Board directed PEC staff to review the installment plan for deposits.

Chris Perry

E. Nodal Market and Power Procurement Risk Management Issues

Bob Wittmeyer and Neil McAndrews presented a report on Nodal Market and Power

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Procurement Risk.

The Board recessed to break at 5:14 PM and reconvened from break at 5:22 PM.

15. Report From Power Supply Manager

President Larry Landaker informed the audience that we would move to agenda item # 15 (Report from Power Supply Manager) after agenda item # 11 (Report on Monthly Operations).

Power Supply Manager, Dale Jones made a presentation on year end review of power supply activities. He also reported that we will ask LCRA to attend the January 2011 Board Meeting and Acting CEO Luis Garcia will follow up with the invitation to LCRA.

President Larry Landaker without objection asked Sue Barnett to come forward and give her report in reference to agenda item # 16, Resource Planning Policy. She also asked the Board to consider the proposed Resource Planning Policy and thanked them for their consideration.

A. Year End Review of Power Supply

16. Energy Committee

A. EC - Reports

B. EC - Action Items/Other Items

1. (Resolution 2010-120) Resource Planning Policy

Director Patrick Cox offered the following amendment to the proposed Resource Planning Policy. Director Chris Perry seconded the amendment. The amendment passed with Director Cristi Clement opposed.

IRP Contents, # a - Add, "including load forecasts, growth projections and economic data analysis."

Director Patrick Cox offered the following amendment to the proposed Resource Planning Policy. Director Kathy Scanlon seconded the amendment. The amendment passed unanimously.

IRP Contents, Add item # h - consideration of pilot projects for implementation and analysis.


MOVER: Chris Perry, District 4 Director/Vice President


AYES: Clement, Scanlon, Perry, Landaker, Cox

NAYS: Ross Fischer

2. (Resolution (ID # 1491)) Conservation Programs

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RESULT: TABLED [UNANIMOUS] Next: 1/24/2011 10:00 AM


17. Audit Committee

A. AC - Reports

B. AC - Action Items/Other Items

1. (Resolution (ID # 1490)) Authority of Audit Committee Chair to Execute Certain Contracts



18. Compensation Committee

A. CC - Reports

B. CC - Action Items/Other Items

19. Executive Search Committee

A. ESC - Reports

1. Approved Executive Search Committee Minutes 2010-09-08

2. Approved Executive Search Committee Minutes 2010-11-10

B. ESC - Action Items/Other Items

20. Financial Strategies, Contracts, and Budget Committee.

A. FSCB - Reports

1. Financial Strategies, Contracts & Budget Committee Minutes October 2010

2. Financial Strategies, Contracts & Budget Committee Minutes November 2010

B. FSCB - Action Items/Other Items

1. Bad Debt Reduction-Credit Risk Assessment; Amendments to Tariff and Business Rules

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Director Cristi Clement moved to accept the proposed business rules and tariffs in connection with "Bad Debt Reduction-Credit Risk Assessment. Director Kathy Scanlon seconded the motion. Directors voted unanimously to accept the proposed business rules and tariffs, as attached.

2. (Resolution 2010-121) Member Assistance Program Policy Revision

Director Patrick Cox offered the following amendment to the proposed Member Assistance Policy. Director Cristi Clement seconded the amendment. The amendment passed with Director Chris Perry opposed.

First bullet point should read as follows:

Participating Community Action, other qualified organizations and county agencies will

qualify members seeking assistance consistent with Comprehensive Energy Assistance

Program requirements.


MOVER: Cristi Clement, District 1 Director/Secretary-Treasurer


AYES: Clement, Scanlon, Fischer, Landaker, Cox

NAYS: Chris Perry

3. (Resolution 2010-122) Capital Credits Policy





4. (Resolution 2010-123) Bylaws Revision for Capital Credits Discounting





21. Governance, Bylaws and Legal Committee.

A. GBL - Reports

1. GBL Committee Minutes of 11-1-10

B. GBL - Action Items/Other Items

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1. (Resolution 2010-124) Change of Title from General Manager to Chief Executive Officer





2. (Resolution (ID # 1488)) Amendment to Delegation of Authority Regarding General Counsel



22. General Manager

A. GM - Reports

1. 2010 Year in Review

Acting CEO Luis Garcia presented his year end report and thanked the Board on behalf of all employees for the action taken by the Board on the Key Performance Indicators (KPI) payment.

B. GM - Action Items/Other Items

C. Announcements

Acting CEO Luis Garcia reported on the following:

Disaster Recovery Site:The Disaster Recovery Site in San Marcos provides PEC the infrastructure needed to ensure the on-going data availability and continuous business operations of its critical applications and processes, particularly in the event of an emergency or disaster.

PEC Coat Drive:PEC employees in Johnson City teamed up with the Blanco County Future Farmers of America and the Blanco County 4-H Clubs to make the Blanco County Warm Your Heart Coat Drive a success. About 500 winter coats were donated in less than a month.

23. Future Items for Board Consideration

24. Future Meetings

A. Consider scheduling January Regular Board Meeting for 10 am on, Tuesday, January 18, 2011 or 10am on Monday, January 24, 2011, at the PEC Headquarters.

Director Patrick Cox moved to schedule the January Board Meeting for January 24, 2011, Monday, 10:00 AM, at the PEC Headquarters. Director Kathy Scanlon seconded the motion. Directors consented unanimously on the motion.

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25. Adjourn

President Larry Landaker thanked all employees for their work and great progress. He also wished everyone a happy holiday season.

There being no further business to come before the Board the meeting was adjourned without objection at 6:52 PM.

____________________________________Cristi Clement, Secretary

APPROVED:

__________________________________Larry Landaker, President

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Sponsors:


Updated: 12/15/2010 11:27 AM by Sylvia A. Romero Page 1

Subject: Melinda L. Armbruster Retirement Resolution



Background:

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Pedernales Electric Cooperative, Inc.Regular Meeting

December 20, 2010


Retirement of Melinda L. Armbruster, after 27 years of service.


Whereas, Melinda L. Armbruster will retire from her employment with Pedernales Electric Cooperative, Inc. after faithfully and competently serving the members of PEC in various capacities for 27 years; and,

Whereas, Melinda L. Armbruster has successfully applied her considerable energy, experience, and knowledge to providing the Members of Pedernales Electric Cooperative, Inc. with reliable electric service; and,

Whereas, in the course of her employment, Melinda L. Armbruster has earned the friendship and respect of the Directors, Employees, and Members of Pedernales Electric Cooperative, Inc. for whom and with whom she has worked; and,

Whereas, Melinda L. Armbruster’s experience and willingness to serve will be sorely missed by the Members, Employees, and Board of Directors of Pedernales Electric Cooperative, Inc.; and,

Whereas, the Board of Directors of Pedernales Electric Cooperative, Inc. of Johnson City, Texas, thinks it fit and proper that a Resolution be passed and spread upon the minutes recognizing the contributions made by Melinda L. Armbruster;

Now, Therefore, be it resolved by the Board of Directors of Pedernales Electric Cooperative, Inc. of Johnson City, Texas, that all Members, Employees, Officers, and Directors of Pedernales Electric Cooperative, Inc. hereby express their great appreciation to Melinda L. Armbruster and their gratitude for the incalculable service rendered by Melinda L. Armbruster to her fellow employees and friends of Pedernales Electric Cooperative, Inc., and,

Be It Further Resolved that this resolution be delivered to Melinda L. Armbruster.

2.A

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Sponsors:



Subject: Shirley A. Runyon Retirement Resolution

Submitted By: Sylvia A. Romero


Background:

2.B

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December 20, 2010


Retirement of Shirley A. Runyon, after 26 years of service.


Whereas, Shirley A. Runyon will retire from her employment with Pedernales Electric Cooperative, Inc. after faithfully and competently serving the members of PEC in various capacities for 26 years; and,

Whereas, Shirley A. Runyon has successfully applied her considerable energy, experience, and knowledge to providing the Members of Pedernales Electric Cooperative, Inc. with reliable electric service; and,

Whereas, in the course of her employment, Shirley A. Runyon has earned the friendship and respect of the Directors, Employees, and Members of Pedernales Electric Cooperative, Inc. for whom and with whom she has worked; and,

Whereas, Shirley A. Runyon’s experience and willingness to serve will be sorely missed by the Members, Employees, and Board of Directors of Pedernales Electric Cooperative, Inc.; and,

Whereas, the Board of Directors of Pedernales Electric Cooperative, Inc. of Johnson City, Texas, thinks it fit and proper that a Resolution be passed and spread upon the minutes recognizing the contributions made by Shirley A. Runyon;

Now, Therefore, be it resolved by the Board of Directors of Pedernales Electric Cooperative, Inc. of Johnson City, Texas, that all Members, Employees, Officers, and Directors of Pedernales Electric Cooperative, Inc. hereby express their great appreciation to Shirley A. Runyon and their gratitude for the incalculable service rendered by Shirley A. Runyon to her fellow employees and friends of Pedernales Electric Cooperative, Inc., and,

Be It Further Resolved that this resolution be delivered to Shirley A. Runyon.

2.B

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Sponsors:

RESOLUTION 2010-125 DOC ID: 1498 B

Updated: 1/14/2011 11:27 AM by Sylvia A. Romero B Page 1

Subject: Transmission Line Construction Agreement


Department: General Manager

Background:

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December 20, 2010

RESOLUTION 2010-125

Transmission Line Construction Agreement

RESOLVED BY THE BOARD OF DIRECTORS OF THE COOPERATIVE, that change orders for the Marshall Ford to Buttercup Transmission Line project totaling $492,533.90 are approved for transmission line engineering and construction services as included in the 2010 - 2014 Cooperative Capital Improvement Plan; and

BE IT FURTHER RESOLVED, that all actions taken prior to the effective date hereof by the authorized agents of the Cooperative, including, but not limited to, the authorization of any change orders with respect to such project are hereby confirmed, ratified and approved.






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Sponsors:



Subject: Approval of Wage & Salary Policy



Background:

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December 20, 2010

RESOLUTION 2010-126

Approval of Wage & Salary Policy, including Wage Scale

RESOLVED BY THE BOARD OF DIRECTORS OF THE COOPERATIVE, that the Cooperative adopts the Wage and Salary Policy, including the Wage Scale, as described in Executive Session of this meeting effective as of January 1, 2011; and

BE IT FURTHER RESOLVED, that the Wage and Salary Policy last approved July 17, 2006 and the Wage Scale last approved May 19, 2008 are hereby superseded; and

BE IT FURTHER RESOLVED, that the Acting General Manager or his designee is authorized to take such actions as needed to implement this resolution, including, without limitation implementation of a Classification Plan for employees.




AYES: Kathryn Scanlon, Chris Perry, Ross Fischer, Dr. Patrick Cox

NAYS: Cristi Clement, Larry Landaker

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Sponsors:

RESOLUTION 2010-127 DOC ID: 1495 A

Updated: 1/14/2011 11:18 AM by Sylvia A. Romero A Page 1

Subject: Employee Defined Benefit Plan Third Amendment



Background:ATTACHMENTS:

• Corrective Amend #3 - RW 12 6 10 _2_ (PDF)

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December 20, 2010

RESOLUTION 2010-127

Employee Defined Benefit Plan Third Amendment

WHEREAS, on November 15, 2010, the Board of Directors adopted the Second Amendment to the Plan, for the purpose of compliance with certain provisions of the Heroes Earnings Assistance and Relief Tax Act of 2008 (“HEART Act”), changes to the retirement plan direct rollover rules as required by the Worker, Retiree and Employer Recovery Act of 2008, to clarify the Plan’s provisions related to military and non-military leaves of absence, and to set the pre-retirement death benefit of the Plan equal to the present value of a participant’s accrued benefit; and

WHEREAS, it was subsequently determined that two provisions of the Second Amendment may have given the appearance of operating upon each other in an unintended manner, thus deleting the Plan’s HEART Act provision; and

WHEREAS, under existing law, all Plan amendments required by the HEART Act were required to be adopted no later than December 31, 2010; and

WHEREAS, in view of said deadline, on December 20, 2010, the Plan Sponsor adopted a corrective Third Amendment for the purpose of removing any ambiguity in the Plan’s provisions affecting the pre-retirement death benefit that is intended to comply with the HEART Act.

NOW, THEREFORE, IT IS RESOLVED that the Plan is hereby amended by adoption of the Third Amendment, and effective as described in the Third Amendment attached hereto and incorporated herein.





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Sponsors:

RESOLUTION 2010-128 DOC ID: 1446 C

Updated: 1/14/2011 11:20 AM by Sylvia A. Romero C Page 1

Subject: 2010 Defined Benefit Plan Funding



Background:

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December 20, 2010

RESOLUTION 2010-128

2010 Defined Benefit Plan Funding

WHEREAS, Pedernales Electric Cooperative, Inc. (“Plan Sponsor”) maintains a qualified retirement plan called the Pedernales Electric Cooperative, Inc. Employees Defined Benefit Retirement Plan (“Plan”) for the benefit of its eligible employees; and

WHEREAS, on April 19, 2010 the Board of Directors of the Plan Sponsor adopted a Defined Benefit Plan Funding Policy that establishes certain objectives for management of the assets of the Plan; and

WHEREAS, said objectives call for the Plan’s Adjusted Funding Target Attainment Percentage (“AFTAP”) for any given plan year to be maintained at a minimum level of 80%; for contributions required to meet the Plan’s federal minimum required contribution to be made timely; and for contributions to be made in approximately level amounts over a 3- to 5-year funding timeline; and

WHEREAS, Rudd and Wisdom, Inc., the Plan’s actuaries, have presented certain funding scenarios for the consideration of the Board of Directors, and the Audit Committee of the Board of Directors has considered said scenarios and, based on the objectives of the Defined Benefit Plan Funding Policy, has made its recommendation to the Board of Directors.

NOW, THEREFORE, IT IS HEREBY RESOLVED that the Chief Financial Officer of Pedernales Electric Cooperative, Inc., the Plan Sponsor, is directed to deposit the amount of $6,235,000 into the Trust associated with the Pedernales Electric Cooperative, Inc. Employees Defined Benefit Retirement Plan no later than December 31, 2010.





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THIRD AMENDMENT TO THE PEDERNALES ELECTRIC COOPERATIVE, INC.

EMPLOYEES DEFINED BENEFIT RETIREMENT PLAN

RESTATED EFFECTIVE JANUARY 1, 2002

This Third Amendment to the Pedernales Electric Cooperative, Inc. Employees Defined Benefit Retirement Plan (“Plan”) is hereby adopted by Pedernales Electric Cooperative, Inc. (“Plan Sponsor”).

WITNESSETH

Whereas, the Plan Sponsor has heretofore maintained and administered the Plan and related Trust in a manner intended to ensure that the Plan continues to qualify under Code sections 401(a) and 501(a) of the Internal Revenue Code of 1986; and

WHEREAS, the Plan Sponsor reserved the right to amend the Plan; and

WHEREAS, under the terms of the Plan, the Plan Sponsor has the continuing ability to amend the Plan, most recently restated the Plan effective January 1, 2002; and

WHEREAS, the Board of Directors desires to amend the Plan during 2010 for the purpose of clarifying the Plan’s provisions related to the pre-retirement death benefit.

NOW, THEREFORE, in consideration of the premises and mutual covenants contained herein, the Plan Sponsor hereby amends the Plan effective as specified below, as follows:

Plan Section 4.06(a)(1) is hereby amended effective January 1, 2007 to read as follows: “(1) Active Participant – Notwithstanding any provision of this plan to the contrary, in the case of a death occurring on or after January 1, 2007, if a participant dies while performing qualified military service (as defined in Code Section 414(u)), the survivors of the participant are entitled to the same benefits that would have been provided under this plan had the participant resumed employment on the day before his death and then terminated employment on account of death. In the event of the death of an active participant prior to January 1, 2011 and prior to the commencement of payment of any benefits hereunder, a benefit which is the excess, if any, of (i) the greater of (A) the present value of his accrued benefit or (B) 100 times his expected monthly normal retirement benefit plus the value of his employee derived accrued benefit over (ii) $50,000 shall be paid to his beneficiary subject to Section 4.06(a)(3). The value of this death benefit, however, shall in no event be less than the greater of the value of the pre-retirement surviving spouse annuity described in Section 4.06(a)(3) or the value of the participant’s employee derived accrued benefit. For purposes of this paragraph, a participant’s expected monthly normal retirement benefit is the amount determined pursuant to Section 4.01(c) assuming that the participant continues in service to his normal retirement age at his current rate of considered monthly compensation.

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Effective January 1, 2011, in the event of the death of an active participant after December 31, 2010 and prior to the commencement of payment of any benefits hereunder, a benefit which is the present value of his accrued benefit shall be paid to his beneficiary subject to Section 4.06(a)(3).” Except to the extent expressly amended hereby, the terms and conditions of the Plan are and shall remain in full force and effect. IN WITNESS WHEREOF, Pedernales Electric Cooperative, Inc. has caused this amendment to be executed and attested hereto this 20th day of December, 2010. PEDERNALES ELECTRIC COOPERATIVE, INC. By: Name: Larry Landaker Title: President - Board of Directors ATTEST By: Name:

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Sponsors:

RESOLUTION 2010-129 DOC ID: 1514


Subject: PEC Strategic Plan




• PEC Strategic Issues 12-20-10-Final (PDF)

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December 20, 2010

RESOLUTION 2010-129

PEC Strategic Plan

RESOLVED BY THE BOARD OF DIRECTORS OF THE COOPERATIVE, that the draft PEC Strategic Issues document is hereby approved for posting to the Cooperative's website beginning January 3, 2011 for member review and comment through January 14, 2011; and






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DRAFT APPROVED FOR COMMENT 12/20/10; FOR RELEASE JANUARY 3, 2011

Page 1 of 6

PEC Strategic Issues DRAFT APPROVED FOR COMMENT 12/20/10

Mission Statement: The purpose of the Cooperative is to provide safe, reliable, low-cost energy services in fiscally responsible partnership with its Member-owners.

1. Financial Issues A. Corporate Financial Model

i. Develop and implement a rigorous corporate financial model for financial analysis, forecasting, planning, and reporting. This decision support system should provide timely insight into the financial implications of strategic and operational decisions.

B. Chief Financial Officer

i. Develop and implement succession plan for CFO, with strong executive leadership skills and capable of process restructuring, in conjunction with hiring of CEO.

ii. Recruit, develop and retain diverse financial expertise and advanced capability with consideration of Capability Maturity Model Integration (CMMI) or similar standard.

iii. Emphasis on analytical, budgetary, debt management, cost containment, ROI estimating and other analysis as required.

C. Budgeting and Financial Controls

i. Management of a fair and equitable capital credits policy. ii. Manage budget variance to actual and identify and incorporate proposed adjustments

and improvements into future budgeting. iii. Monitor PEC’s performance to industry benchmarks and identify opportunities to

improve efficiency. iv. Implement financial controls to assure asset responsibility and to safeguard Member’s

money. v. Explore the feasibility of restructuring the Cooperative’s debt.

vi. Perform a Cost/Benefits analysis of major programs, functional processes and services and prioritize competing initiatives.

vii. Develop a mechanism for recommended improvements in operational efficiency and financial management policies.

viii. Align and monitor the Cooperative’s budget and ensure sustainability of net income. ix. Monitor and review Member assistance programs, credit and collection plans and write

off policies against measurable results.

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D. Financial Ratios

i. Monitor and achieve financial targets that are consistent with the Cooperative's goals and objectives.

ii. Monitor and improve credit ratings objectives of the Cooperative.

E. SAP (LINKS) Implementation

i. Maintain oversight responsibility, on-time delivery of the SAP (Links) system and achievement of PEC operational readiness coincidental with final acceptance of all contractual terms and conditions.

F. Procurement and Purchasing

i. Develop, recruit, train and implement procurement management skill sets. ii. Efficient management of procurement and purchasing decisions for major expenditures

and investments. iii. Require efficient management of all post awarded contracts.

2. Rate Issues A. Rate Design

i. Reevaluate existing cost-of-service and rate structures with a focus on efficiency, equity, and fairness, the current business environment, and high quality service through low-cost competitive rates.

ii. Design rates to support energy efficiency, Demand Side Management (DSM) and distributed generation demanded by Members.

iii. Maintain unbundled rate structures to ensure accountability to Members by accurately passing through power purchase cost and the Cooperative’s cost of power delivery.

iv. Develop a lifeline rate structure for qualified Members.

B. Rate Concerns

i. Rate design criteria shall be established by the Board. ii. Develop transparency on rates issues, and compare PEC’s rates with other providers.

iii. Demonstrate PEC’s competiveness and improve communication on those comparisons. iv. Inform Members about the rationale behind the rate structures. Develop a long term

communication plan with measurable results to communicate rates in a method that is simple and understandable.

v. Ensure predictable, stable low-cost competitive rates for Members.

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3. Employee Issues A. Management

i. Hire a CEO who understands the Cooperative model, recognizes the issues the Cooperative currently has before it, is an effective change agent and understands the unique role of PEC with its communities and employees.

ii. Launch an effective communication plan to address re-structuring and re-alignment. iii. Reorganize the management structure to identify and develop personnel who have the

leadership skills which best address the strategic goals and objectives of the Cooperative as set by the Board and produce measurable results tied to those goals.

iv. Ensure that the Board and management are working together to provide a creative, constructive and safe working environment for the employees and Members.

v. Develop a plan, to improve trust between employees, the Board and upper management, to establish a unified PEC team.

vi. Implement the actionable findings from Somerset Guild research and measure the results.

vii. Create an environment for accountability that will build and improve the Cooperative through ongoing assessment and evaluation.

B. Employees

i. Restructure the organization utilizing attrition and realignment of duties. ii. Prepare a staffing plan based on metrics consistent with the Cooperative’s goals and

objectives and which will attract loyal high quality, progressive minded management and employees in a financially responsible manner.

iii. Improve PEC’s employee’s effectiveness, accountability and efficiency. iv. Implement changes with minimal disruption to Member operations.

C. Compensation and Training

i. Develop a comprehensive compensation plan, which ensures that PEC offers competitive compensation, benefits and professional development to retain valued employees.

ii. Develop ongoing training for employees to understand the Cooperative business model and its application to serving the best interests of the Membership.

iii. Ensure that the management and executive staff receives the training to manage changes at PEC and within the energy industry.

4. Organizational and Operational Issues A. Facilities

i. Perform a full review of all facilities in which PEC has a presence to determine if a more cost-effective method exists to maintain PEC’s link to the community.

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B. Organization Functions

i. Effectively educate Members on what it means to be a Cooperative and how the Cooperative difference impacts Member’s value.

ii. Create an efficient forward thinking organization prepared to address future challenges. iii. Perform a full review and analysis of the management and organizational structure of

PEC to ensure the right people are in the right places for maximum effectiveness. iv. Implementation of Members Bill of Rights and bylaws into organizational policies and

procedures.

C. Operations Functions

i. Identify and develop sound business cases for cost-effective outsourcing opportunities. ii. Coordinate decision-making processes to increase overall efficiency.

iii. Update policies and procedures manual to ensure the best business practices are being implemented.

iv. Establish meaningful performance metrics for controlling costs and improving productivity.

v. Complete an operational benchmarking analysis and develop companywide process improvement plan and strategy.

5. Communication Issues A. Communications Department

i. Develop, train, and recruit effective, high performance individuals to elevate PEC’s internal and external communications.

ii. Yield a greater Member understanding of cooperatives based on trust with an image of PEC as a desirable energy partner.

iii. Develop and implement an effective communications strategy, both internally and externally, which is focused on PEC’s policies, procedures, directives and initiatives.

iv. Review the communications department structure and activities for efficiency improvements.

B. Strategies

i. Launch, maintain and update newly designed website and implement metrics to measure customer satisfaction, usage, and satisfaction of cost-efficiency goals through alternate billing, and other categories.

ii. Develop cost-effective marketing strategies for PEC. iii. Assess Member needs and expectations through surveys and develop a plan to

communicate to the membership those findings and action plans to address them. iv. Communicate that PEC is a leader among the Cooperative in openness and

transparency. v. Develop and improve a cohesive message in our communication efforts with

policymakers, Members, stakeholders, media and the energy industry regarding PEC’s strategic issues and image.

vi. Establish a plan for communicating emergency and disaster preparedness.

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vii. Develop a strategy toward proactive communications with Members, employees and media.

viii. Develop a plan to respond to questions raised by Members in meetings in a timely manner.

ix. Highlight achievements of cooperatives and reinforce the value that PEC’s business model provides for the community.

6. Power Supply Issues A. Power Supply Providers

i. Coordinate and integrate the Cooperative’s procurement of supply and demand side resources and incentives.

ii. Examine current and prospective power supply obligations and provide rigorous analysis of provisions of those agreements.

iii. Maximize the benefits and exercise effective management over long-term power supply contracts.

iv. Understand the implications of opting into retail competition or complying with legislation requiring retail open access with respect to the Cooperative's obligations under the long-term power supply agreements.

v. Develop a financial model of the Cooperative’s wholesale power purchase agreements to evaluate alternative resource management decisions.

B. Power Supply Strategies

i. Develop a least cost integrated resource plan to achieve the renewable energy and other energy efficiency supply portfolio goals.

ii. Establish and develop a long-term power supply plan which yields a stable and affordable energy supply for the Membership by evaluating all sources of power and new technology.

C. Demand Side Management

i. Develop a portfolio of Demand Side Management (DSM) choices for Members in all customer classes.

ii. Solicit Member feedback on the long-term energy resource plan to better manage Cooperative costs and retail bills, including, energy efficiency as a substitute for traditional generation.

iii. Explore collaborative partnerships with new energy sources. iv. Revise and refresh renewable energy policies.

7. Member Services Issues A. Reliability, Customer Service and Cost

i. Provide safe reliable low cost electric service to the Cooperative’s Members. ii. Provide high quality customer service and reliability while balancing costs.

iii. Maintain Customer Service as the interface with the Members for problem solving and resolution.

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iv. Review the criteria and results of the JD Powers survey on reliability and rates then develop a plan for action on the findings.

v. Review alternative sources for customer satisfaction information (Touchstone, CFC, NRECA, the Cooperative website or similar credible other survey organizations).

B. Membership Involvement

i. Establish an effective process for Member input on Cooperative products and services which supports Member control of Cooperative.

ii. Deploy an ombudsman position to advocate for member interests or problems associated with Member relations.

iii. Educate Members on Cooperative plans and goals and the business model. iv. Implement new bylaw changes and Member’s Bill of Rights. v. Review and enhance new services policies including credit checks for deposit

requirements, and line extensions. vi. Establish a paperless billing option.

vii. Initiate process improvements that result in financial cost reductions to members.

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Sponsors:


Updated: 1/16/2011 3:43 PM by Sylvia A. Romero C Page 1

Subject: 2011 NRECA Meetings Voting Delegate




• 2011 NRECA Voting Delegate Certification (PDF)

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December 20, 2010

RESOLUTION 2010-118

2011 NRECA Annual and Regional Meeting Voting Delegates

RESOLVED BY THE BOARD OF DIRECTORS OF THE COOPERATIVE, that the following Directors are hereby appointed and designated as authorized representatives of the Cooperative to serve as a voting delegate and alternate delegate to act at meetings of the 2011 National Rural Electric Cooperative Association Annual and Regional Meeting until successors are duly appointed and designated: Dr. Patrick Cox, Voting Delegate; and Cristi Clement, Alternate Delegate.



SECONDER: Chris Perry, District 4 Director/Vice President


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NRECA 2011 Annual and Regional Meeting Voting

National Rural Electric Cooperative Association Delegate Certification and

• ® ATouch&tooe Energy' CooperatiVt ~ Credentialing Process

Printed below in the NRECA VOTING DELEGATE CERTIFICATION box are the Voting Delegate and Alternate

Delegate who are presently on file at NRECA for your member system. please review, correct and certify this

information in order to vote at the Business Session for the 2011 Annual and Regional Meeting. Please fax this form to NRECA at (703) 907-5951.

To: To General Manager Region 10 Pedernales Electric Co-op, Inc. Texas PO Box 1 Johnson City, TX 78636-0001

NRECA VOTING DELEGATE CERTIFICATION

NRECA Bylaws Article V, Section 2(B) and 2(C) provide that "Each voting member shall be entitled to select, either by vote of its membership or its board of directors, one of its members, directors or employees to act as the voting delegate, and one such person to act as the alternate delegate, at meetings of the Association. All voting delegates must submit certification signed by the president and secretary of the member that such delegate is duly authorized to cast the vote of the member.1I

Please review the information below and make any necessary carrections or changes. Only those delegotes who have been properly documented as authori%ed by their cooperatives shall be credentialed to act during the NRECA Annual and Regional Meeting Business Session. If there are no changes, check the "No Chonge" box for the delegate and!or alternate delegate. If new delegates have been selected, please provide the new information requested. This Form must be dated, signed by the president and secretary of the member system, and returned to the NRECA office by January 21, 2011.

lhe following are hereby certified as oHicial voting delegate and alternate and are duly authorized 10 cast the vote of this member.

Current Voting Delegate Current Alternate Delegate

Patrick Cox Cristi Clement, CCO o No Change o No Change

New Votinl Delegate: Tide

NewAlternate Delegate: Tide

(The Alternate is certified to act only in the absence of the Delegate.)

Signed President (of member system) DATE Secretary (of member system) DATE

Meeting and Delegate Registration Procedures

o Please fox signed, doted and completed form to NRECA ot(703) 907-5951 by January 21, 2011.

.. Delegates must be registered for the meeting (either in advance or onsitel and receive a badge before they can obtoin their voting credentiols.

., After registering, the delegate must then proceed to the NRECA Voting Delegate Desk thot will be located near the generol meeting registration site.

e At the NRECA Voting Delegate Registration Desk, the delegate's Certification information will be reviewed and the delegate will receive the official delegate ribbon (that should be aRoched to the nome badge) and the assigned voting credential for the meeting.

@) The delegate must bring his/her voting credential to the NRECA Business Session and present it in order to vote. Each voting member is permiHed one vote on each of the resolutions and other business properly brought before the Annual and Regional Meeting Business Session. No individuol may represent more than one voting member system and proxy voting is prohibited at all meetings.

If you have any questions concerning tfte above procedure, please conklct tfte Membership Department at (703) 907-5868.

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Sponsors: District 1 Director/Secretary-Treasurer Cristi Clement


Updated: 12/15/2010 2:55 PM by Sylvia A. Romero A Page 1

Subject: Bylaw Revision - Easements and Rights-of-Way

Submitted By: Pete Slover

Department: Legal Services

Background:

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December 20, 2010

RESOLUTION 2010-119

Bylaw Amendment: Easements/Rights of Way

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Sponsors: District 7 Director Dr. Patrick Cox

RESOLUTION (ID # 1489) DOC ID: 1489 B

Updated: 12/16/2010 3:17 PM by Sylvia A. Romero B Page 1

Subject: Installment Plan for Deposits



Background:

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December 20, 2010


Installment Plan for Deposits

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ERCOT’S NODAL MARKET AND POWER PROCUREMENT RISK MANAGEMENT ISSUES

Effective December 1, 2010

1

Presented to PEC By Bob Wittmeyer and Neil McAndrews Dec 20, 2010

[email protected] [email protected]

Utilities (Both IOUs and Non Profits) Planned and built generation to serve a defined

Service Territory. Generation Plans were based on forecasted: fuel

prices, peak load growth, energy growth, and location specific requirements.

Utilities presented plans to the PUC who would then approve the plans and provide rates which would guarantee recovery of the cost for the generation plans.

Utilities dispatch (operate) generation based on least cost.

Load pays utility based on PUC approved rate.

2

The old power market world

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Pre-Deregulation

Utilities plan, build and dispatch generation to serve specific Load.

PUCT Determines rates paid by loads.

Evolution of the ERCOT Electric Market

Zonal Market

Investors plan and build generation

Utilities Dispatch Contracted Generation

to serve Contracted Load

ERCOT send dispatch signals to utilities, to

serve uncontracted load (5-7%) Market

Nodal Market(Dec 1, 2010)

Investors plan and build generation

ERCOT dispatches nearly all generation.

ERCOT determines the prices Loads pay based on least cost

dispatch

Todays ERCOT Nodal Market(Dec 1, 2010)

• ERCOT dispatches and pays generation based on location specific offers (every 5 minutes).

• ERCOT responsible for physical delivery of energy and system reliability.

4

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(Dec 1, 2010)

• Every 15 minutes, ERCOT determines the prices Loads pay based on Load zone bus prices using least cost dispatch principals.

• Load is financially responsible for delivered energy.

5

Essentially there are 3 separate markets: generation; load; and congestion.

Physical delivery of energy is now ERCOT’s responsibility.

Ownership of generation is purely a financial hedge. The electrical distance between low cost generation

and loads will determine the prices paid to/by each. PEC (or its agent) is financially responsible for the

cost of delivered energy. Value of a generator and the cost to serve load will be

easily determinable after the fact. ERCOT provides tools to help loads manage price

risk.

6

The good and the bad under the new power market world

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Day Ahead Energy Market (DAM) – (Financial) Bids from Loads Offers from Generators

Real-Time Market (Physical & Financial) ERCOT dispatches system based on generation offer

curves Loads pay for generation based on location, Loads get

credit for generation purchased in DAM. Congestion Revenue Rights

Financial tool used to manage congestion costs, they allow an entity to lock in price differences between locations.

Securitization of payments Each counterparty must cover its activity with deposits

7

ERCOT Risk Management tools

Amount of non-long term energy to hedge.

How and if PEC should hedge energy prices for any options it has under its power supply contracts.

PEC as a (NOIE) has the option of purchasing Pre-assigned Congestion Revenue Rights (PCRR’s) at discounts between 80 and 95% to other market participants. Does PEC directly manage the purchase and

allocation of CRR’s or use a third party manager.

8

PEC Risk Management Considerations

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Comprehensive Planning 9

Market Environment Risk Modeling

Rate and Acquisition Objectives

Plan Execution and Process

1

2

3

4 Performance Review

Deregulated MarketERCOT

“Energy Only Market” The spot price market provides signals about the

level of capacity

Market Effect The market needs short term price spikes to

produce net revenues above breakeven economics to induce producers to build more capacity.

1 Market

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Wholesale PowerPortfolio Risk Variables

Market Risk: Uncertainty of power and natural gas prices, market design and implementation

Regulatory Risk: Changes in market design, environmental rules, legislative mandates

Competition Risk: New products from competitive REPs aimed at distribution customers

Contract Risk: Uncertainty of supplier costs and performance

1 Market

Portfolio Costs with Fuel and Congestion Volatility Annual Basis

Variance in wholesale on peak costs year over year of +200% and minus 60%

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Market Prices and Marginal Fuel Prices Both Exhibit High Volatility1 Market

In 2009 no generation technology met net revenue targets (Source: SOM 2009)

1 Market

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Systematic testing of various quantities of resource types and costs, and future market environments

Measures the impacts of different levels and types of fuel hedging strategies

Allows an assessment of the change in fuel price risk based on various quantities and qualities of hedge positions

Measure the impact of various portfolio mixes and hedge quantities to customize a strategy to your needs.

15

Portfolio Management2

Objectives

Risk Management Program

Risk Management Policy

Controls and Authorization

Evaluation and Execution Procedures

Separation of Duties

Reporting

3 Execution

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Hedged and Unhedged Rate Comparison

4 Review

Planning and Risk Management require the measurement of forecast error (Source TVA IRP)

4 Review

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Summary of Planning and Risk Issues

A New Market with New Risks

Simulate and Record Costs Risks

Assess Ideal Portfolio

Develop Policy and Procedures

Measure Performance

Additional Slides

Background Materials

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Risk Assessment Questionnaire

What is your market environment: Regulated or Deregulated?

22

ERCOT Load ZonesWest Load Zone ~ 4,000 MW

Rayburn Load Zone ~ 1,000 MW

North Load Zone ~ 24,000 MW

South Load Zone ~ 7,000 MW

Houston Load Zone ~ 18,500 MW

Austin Load Zone ~ 2,700 MW

LCRA Load Zone ~ 3,900 MW

San Antonio Load Zone ~ 4,800 MW

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~ 9,700 MW of Wind - ~ 6,300 deliverable

~ 4,400 MW of Nukes

~ 17,000 MW of Solid Fuel (Coal/Lignite)

~ 24,000 MW of Combined Cycle

~ 18,000 MW of Gas Steam

~ 3,000 MW Quick Start

ERCOT 2010 Generation Makeup

23

Independent Market Monitors Review of Breakeven Costs for Natural Gas Units (Source SOM

Report 2009)

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25

Marginal Market Trend Fuel Conversion Efficiency Index

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$0 $1 $3 $4 $5 $6 $8 $9 $10

$11

$13

$14

$15

$16

$18

$19

$20

$21

$23

$24

27

Understanding your risk exposure.

What if I lock in a price of $5.25?

Miss low costs Avoid high costs

HedgeOpportunityCost

HedgeBenefit

Risk Modeling Monte Carlo ExampleA Probability Distribution of Texas Natural Gas Prices

5.0% 90.0% 5.0%0.0% 82.2% 17.8%

1.491 2.114

1.2

1.4

1.6

1.8

2.0

2.2

2.4

2.6

2.8

Values in Billions ($)

Hedge 0% Mean = $

StdDev = $

Hedge 100% CapsMean = $

StdDev = $

Hedge 100% FirmMean = $

StdDev = $

28

Optimize your portfolio mix under multiple scenarios.

DOWN Forecast

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29

The US economic recession lowers load forecasts in ERCOT

(source ERCOT Summer CDR 2008 & 2010)

Competitive Market Reacts Quickly to Changes in Costs

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Traditional Non-Profits advantage narrows with lower Natural Gas

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2010 Power Supply Review

December 20, 2010

Power Supply ActivitiesOver 99% of Power Supply managed under terms

of our LCRA Wholesale Power Agreement• Customer Supply Option Provision (35% Max)

– Intermittent Progressive Power Generation (IPPG)• Up to 15% Energy Requirements per Settlement Period

• 2009 Added 90 MW Capacity from South Trent Wind Farm

– Market Pricing Option (MPO)• 10% of Energy Requirements per Settlement Period Effective June

25, 2010

– Load Release (LR)• Initiated LR of 10% of Energy Requirements per Settlement Period

Effective June 25, 2010

• Renegotiated Power Purchase Agreement for non-LCRA Load in Junction District

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Power Supply Activities• Other Progressive Power Activities

– LCRA Energy Efficiency Working Group• The Good Company & ITRON Assessment

– Demand Management Pilot Program• 125 Members Piloting Consert Product

– A&M Smart Grid Consortium • Utility Specific Model

– Distributive Generation• 93 Interconnect Agreements• 374 KW of Total Generation

– 316 KW Solar– 58 KW Wind

2010 YTD 3rd QuarterPower Purchases

• LCRA 3,623,435 MWH• MPO 162,521 MWH• LR 162,521 MWH• South Trent 184,346 MWH• Junction 22,163 MWH

Total 4,154,986 MWH

Renewable Energy Credits (REC) & Capacity• 1 REC = 1,000 KWH = 1 MWH

LCRA Wind 2,378 REC’s 89 MWSouth Trent 184,346 REC’s 90 MWTotal Wind 186,274 REC’s 179 MWLCRA Hydro 106,325 MWH 79 MWTotal Renewable 292,599 MWH 258 MW

• % Renewable Capacity 23%• % Renewable Energy 7%

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Power Costs• Includes Generation, Ancillary, Transmission, Congestion,

Losses and ERCOT Fees and Uplifts• South Trent Premium Cost $2.7mm YTD 3rd Q• $0.07208/KWH Base Power Cost Effective Aug. 2009• Power Cost Adj. (PCA) Utilized to Reflect Changes• PCA Changes

– Dec. 2009 ($0.0027)/KWH– June 2010 ($0.0070)/KWH – Sept. 2010 ($0.0130)/KWH – Jan. 2011 One Month PCA Associated with LCRA Refund

• LCRA is Cost Based• Revenue Greater Than Required• PEC’s Portion $10.4mm

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Planned Energy Committee Activities

• Enhanced Member Participation and Transparency Related to:– Integrated Resource Planning

• LCRA Resource Planning

• Power Purchases

• Distributive Generation/Interconnection

• Demand Management/Energy Efficiency

• Other Progressive Power Opportunities

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Sponsors: District 4 Director/Vice President Chris Perry


Updated: 12/14/2010 2:38 PM by Aisha N Hagen C Page 1

Subject: Resource Planning Policy

Submitted By: Luanne Coleman

Department: Committee - Energy


• IRP - Approved by Board - Dec 20 (PDF)

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December 20, 2010

RESOLUTION 2010-120

Resource Planning Policy

NOW, THEREFORE, BE IT RESOLVED BY THE BOARD OF DIRECTORS OF THE COOPERATIVE, that the Cooperative adopts the Resource Planning Policy as attached, with any amendments approved by the Board this day, to be effective as of January 1, 2011; and

BE IT FURTHER RESOLVED, that any policy concerning integrated resource planning, including the May 18, 2009 board resolution on Integrated Resources Policy and final determination on integrated resource planning approved previous to this day is hereby superseded; and



MOVER: Chris Perry, District 4 Director/Vice President


AYES: Clement, Scanlon, Perry, Landaker, Cox

NAYS: Ross Fischer

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RESOURCE PLANNING POLICY

BOARD ADOPTED: December 20, 2010

This policy governs PEC’s planning for and procurement of resources to meet its requirements for energy services.

The Pedernales Electric Cooperative will provide reliable energy services – electricity and other services – using a “least cost” mix of resources to meet the demand for energy on its system. In furtherance of this policy PEC will plan for and select supply and demand resources according to a Board-approved “integrated resource plan” developed every three years.

POLICY

PEC will develop and implement best practices in integrated resource planning so that the full range of energy resources, including power purchases, energy conservation and efficiency, renewable energy sources, cogeneration and other distributed energy resources are evaluated and procured on a consistent, integrated and competitive basis. PEC shall also seek and consider member input in developing its integrated resource plan.

The integrated resource plan will describe the portfolio of energy resources that PEC plans to use in order to meet current and future needs for energy at the lowest reasonable cost to PEC members. To determine the lowest reasonable cost the PEC will consider:

Integrated Resource Plan

1) All direct costs of an energy resource over its available life, including the cost of production, distribution, transportation, utilization, and waste management.

2) In addition to direct costs the Cooperative shall consider:

a) the effect on the rates and bills of different types of members;

b) the uncertainty of costs related to future fuel requirements, regulatory compliance and other risk factors;

c) the appropriate mix of cost-effective energy resources including fueled and non-fueled resources such as renewable resources, power purchases, distributed generation, energy efficiency measures and a mixture of short-term and long-term contracts; and

d) the cost of compliance with all applicable federal, state and local environmental laws, rules, and orders;

The integrated resource plan shall consider:

IRP Contents

a) A range of forecasts of future energy demand, including load forecasts, growth projections and economic data analysis;

b) An assessment of commercially available energy efficiency and demand side management measures and practices, including energy management;

c) An assessment of currently employed and new policies and programs needed to ensure that the energy resources are developed;

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2

d) An assessment of a wide range of conventional and commercially available nonconventional distributed generating technologies;

e) An assessment of distribution and transmission system capability and reliability;

f) A comparative evaluation of energy supply resources (including transmission and distribution), distributed energy resources, and improvements in efficiency;

g) Integration of the demand forecasts and resource evaluations into a long-range (e.g., at least ten years; longer if appropriate to the life of the resources considered) integrated resource plan describing the mix of resources that is designated to meet current and projected future needs for energy services at the lowest reasonable cost to Cooperative members;

h) consideration of pilot projects for implementation and analysis;

i) proposed requests for proposals demand side or supply side resources, or both; and

j) input from its wholesale power suppliers.

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Sponsors:


Updated: 1/19/2011 9:35 AM by Renee Oelschleger B Page 1

Subject: Conservation Programs



Background:

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December 20, 2010


Conservation Programs

RESOLVED BY THE BOARD OF DIRECTORS OF THE COOPERATIVE, that theCooperative will continue to offer a cost-effective Energy Audit Program, Commercial Lighting Rebate Program, and HVAC Rebate Program; and

BE IT FURTHER RESOLVED that the Cooperative will ensure that these energy efficiency programs meet the cost-effectiveness standards established by the Public Utility Commission of Texas in Substantive Rule 25.181 (d); and

BE IT FURTHER RESOLVED, that the Acting Chief Executive Officer or his designee isauthorized to take such actions as needed to implement this resolution.



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Sponsors:

RESOLUTION (ID # 1490) DOC ID: 1490 A

Updated: 12/14/2010 6:20 PM by Aisha N Hagen A Page 1

Subject: Audit Committee Chair Engagement Letter Authority



Background:

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December 20, 2010


Authority of Audit Committee Chair to Execute Certain Contracts

RESOLVED BY THE BOARD OF DIRECTORS OF THE COOPERATIVE, that the Chair of the Audit Committee is, authorized, as a duly authorized agent of the Cooperative, for and in the name and on behalf of the Cooperative, to execute any engagement letter(s) with internal and external auditors, consistent with and pursuant to terms of such engagements as approved by Board resolution.



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Pedernales Electric Cooperative, Inc.

Business Rules

201 South Avenue F P. O. Box 1

Johnson City, Texas 78636-0001

Adopted December 20, 2010

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Pedernales Electric Cooperative, Inc. Business Rules

Table of Contents

Topic Page General Provisions .....................................................................................................................................3

Statement of Nondiscrimination................................................................................................................3

Definitions....................................................................................................................................................3

Request for Service ....................................................................................................................................5

Refusal of Service .......................................................................................................................................5

Credit Requirements...................................................................................................................................6

Issuance and Format of Bills .....................................................................................................................9

Spanish Language Requirements .............................................................................................................9

Bill Payment and Adjustments ..................................................................................................................9

Disconnection of Service .........................................................................................................................11

Complaints.................................................................................................................................................13

Information to Applicants and Members ................................................................................................13

Member Access to Cooperative Records...............................................................................................14

Reliability and Continuity of Service.......................................................................................................15

Meter Requirements..................................................................................................................................16

Meter Records ...........................................................................................................................................17

Meter Readings .........................................................................................................................................17

Meter Testing.............................................................................................................................................17

Adjustments Due to Meter Errors............................................................................................................17

Meter Tampering .......................................................................................................................................18

Interconnection Meters and Circuit Breakers ........................................................................................18

Member Service Option.........................................................................................................................................18

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PEDERNALES ELECTRIC COOPERATIVE, INC. BUSINESS RULES

Page 3 Adopted 12-20-2010

General Provisions These rules will not relieve in any way the Cooperative or member from any of its duties under the laws of the State of Texas or the United States. If any provision of these rules is held invalid, such invalidity should not affect other provisions or applications of these rules which can be given effect without the invalid provision or application, and to this end, the provisions are declared to be severable. The purpose of the rules is to establish minimum member service standards the Cooperative will follow in providing electric service. The Cooperative may make exceptions to these rules for good cause.

Statement of Nondiscrimination Pedernales Electric Cooperative, Inc. shall not discriminate on the basis of race, color, nationality, religion, sex, marital status, disability, income level, or source of income, and shall not unreasonably discriminate based on geographic location.

Definitions The following words and terms should have the following meanings, unless the context clearly indicates otherwise:

1) Applicant—A person who applies for service.

2) Commission—The Public Utility Commission of Texas.

3) Cooperative corporation—The Cooperative corporation organized and operating under the Electric Cooperative Corporation Act, Texas Utilities Code Annotated, Chapter 161, or a predecessor statute to Chapter 161 and operating under that chapter.

4) Days—Unless the context clearly indicates otherwise, the term “days” should refer to calendar days.

5) Electric utility—

A. A person or river authority that owns or operates for compensation in the State of Texas equipment or facilities to produce, generate, transmit, distribute, sell, or furnish electricity in the State of Texas. The term includes a lessee, trustee, or receiver of an electric utility and a recreational vehicle park owner who does not comply with Texas Utilities Code, Subchapter C, Chapter 184, with regard to the metered sale of electricity at the recreational vehicle park. The term does not include:

i. A municipal corporation;

ii. A qualifying facility;

iii. A power generation company;

iv. An exempt wholesale generator;

v. A power marketer;

vi. A corporation described by the Public Utility Regulatory Act §32.053 to the extent the corporation sells electricity exclusively at wholesale and not to the ultimate member;

vii. An electric cooperative;

viii. A retail electric provider;

ix. The State of Texas or an agency of the state; or

x. A person not otherwise an electric utility who:

a. Furnishes an electric service or commodity only to itself, its employees, or its tenants as an incident of employment or tenancy, if that service or commodity is not resold to or used by others;

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b. Owns or operates in the State of Texas equipment or facilities to produce, generate, transmit, distribute, sell or furnish electric energy to an electric utility, if the equipment or facilities are used primarily to produce and generate electric energy for consumption by that person; or

c. Owns or operates in the State of Texas a recreational vehicle park that provides metered electric service in accordance with Texas Utilities Code, Subchapter C, Chapter 184.

B. With respect to transmission service and ancillary service, the term includes municipally owned utilities and river authorities that are not otherwise subject to the commission’s rate setting authority.

6) Essential Services—Members whose operations are essential to the safety, health and welfare of the community; including but not limited to hospitals, police stations, fire stations, critical water, wastewater, and communications facilities.

7) Facilities—All the plant and equipment of the Cooperative, including all tangible and intangible real and personal property without limitation, and any and all means and instrumentalities in any manner owned, operated, leased, licensed, used, controlled, furnished, or supplied for, by, or in connection with the business of the Cooperative, including any construction work in progress.

8) License—The whole or part of any commission permit, certificate, approval, registration, or similar form of permission required by law.

9) Member—Any person, firm, corporation or body politic that has applied for service and has paid the Cooperative’s membership fee.

10) Member class—A group of members with similar electric use service characteristics (e.g., residential, commercial, industrial) taking service under one or more rate schedules.

11) Municipality—A city, incorporated village, or town, existing, created, or organized under the general, home rule, or special laws of the state.

12) Payment arrangements—A payment arrangement is any agreement between the Cooperative and a member that allows a member to pay the outstanding bill after its due date but before the due date of the next bill.

13) Person—Any legal or natural person.

14) Power marketer—A person who becomes an owner of electric energy in the State of Texas for the purpose of selling the electric energy at wholesale; does not own generation, transmission, or distribution facilities in this state; does not have a certificated service area; and who is in compliance with the registration requirements of the Commission.

15) Premises—A tract of land or real estate including buildings and other appurtenances thereon.

16) Public Utility Regulatory Act (PURA)—The enabling statute for the Commission of Texas, located in the Texas Utilities Code Annotated, §§11.001 et.seq.

17) Qualifying cogenerator—The meaning as assigned this term by 16 U.S.C. §796(18) (C).

18) Qualifying facility—A qualifying cogenerator or qualifying small power producer.

19) Qualifying small power producer—The meaning as assigned this term by 16 U.S.C. §796(17) (D).

20) Rate—Includes:

A. Any compensation, tariff, charge, fare, toll, rental, or classification that is directly or indirectly demanded, observed, charged, or collected by the Cooperative for a service, product, or commodity described in the definition of electric utility in this section; and

B. A rule, practice, or contract affecting the compensation, tariff, charge, fare, toll, rental, or classification.

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21) Regulatory authority—In accordance with the context where it is found, either the Commission, the governing body of a municipality, or Board of Directors of the Cooperative.

22) Rule—A statement of general applicability that implements, interprets, or prescribes law or policy, or describes the procedure or practice requirements of the regulatory authority. The term includes the amendment or repeal of a prior rule, but does not include statements concerning only the internal management or organization of the regulatory authority and not affecting private rights or procedures.

23) Service—The term includes any act performed, anything supplied, and any facilities used or supplied by the Cooperative in the performance of its duties.

24) Tariff—The schedule of the Cooperative containing all rates and charges stated separately by type of service and the rules and regulations of the Cooperative.

25) Tenant—A person who is entitled to occupy a dwelling unit to the exclusion of others and who is obligated to pay for the occupancy under a written or oral rental agreement.

Request for Service The Cooperative should initiate service to each qualified member or applicant for service as described in the Tariff within its certificated area in accordance with this section.

1) The member or applicant grants the Cooperative easement rights and acquires all necessary easements from adjacent landowners on a form acceptable to the Cooperative for its facilities. All costs and expenses, if any, related to the acquisition of easements to serve the member or applicant shall be the responsibility of the member or applicant, including the Cooperative’s costs and expenses if the Cooperative participates in the acquisition of the easements through condemnation proceedings.

2) Applications for new electric service not involving line extensions or construction of new facilities should be connected within two working days after the member or applicant has met the credit requirements as referenced in the rule herein entitled Credit Requirements and complied with all applicable state and municipal regulations.

3) The Cooperative may require a member or applicant requesting service to satisfactorily establish credit as referenced in the rule herein entitled Credit Requirements, but such establishment of credit should not relieve the member from complying with rules for prompt payment of bills.

4) Requests for new service requiring construction, such as line extensions, should be completed within 90 days, unless delayed by a cause beyond the reasonable control of the Cooperative, or a time period agreed to by the member or applicant and the Cooperative; and if the member or applicant has met the credit requirements or has made satisfactory payment arrangements for construction charges, and has complied with all applicable state and municipal regulations.

5) If facilities must be constructed, the Cooperative should contact the member or applicant and give the member or applicant an estimated completion date and an estimated cost for all charges to be incurred by the member or applicant.

6) The Cooperative should explain any construction cost options such as sharing of construction costs between the Cooperative and the member or applicant following the assessment of necessary line work.

7) Each individual residential unit in apartment complexes, condominiums, etc., will be separately metered, and shall be subject to all related provisions and fees of the Tariff and the Business Rules.

Refusal of Service 1) Acceptable reasons to refuse service—The Cooperative may refuse to serve an applicant or

member for any of the reasons identified below.

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A. Applicant’s facilities inadequate—The applicant’s or member's installation or equipment is known to be hazardous or of such character that satisfactory service cannot be given, or the applicant’s facilities do not comply with all applicable state and municipal regulations.

B. Violation of the Cooperative’s tariffs—The applicant or member fails to comply with the Cooperative’s tariffs pertaining to operation of nonstandard equipment or unauthorized attachments which interfere with the service of others. The Cooperative should provide the applicant notice of such refusal and afford the applicant a reasonable amount of time to comply with the Cooperative’s tariffs.

C. Intent to deceive—The applicant or member applies for service at a location where another member received, or continues to receive, service and the Cooperative bill is unpaid at that location, and the Cooperative can prove the change in identity is made in an attempt to help the other member avoid or evade payment of the Cooperative bill. An applicant or member may request a supervisory review as referenced in the rule entitled Complaints if the Cooperative determines that the applicant or member intends to deceive the Cooperative and refuses to provide service.

D. For indebtedness—The applicant or member owes a debt to the Cooperative for the same kind of service as that being requested.

E. Refusal to pay a deposit. Refusing to pay a deposit if applicant or member is required to do so under the Credit Requirements.

2) Applicant’s or member's recourse—If the Cooperative has refused to serve an applicant or member, the Cooperative will inform the applicant of the reason for its refusal and the applicant may file a complaint as referenced in the rule entitled Complaints.

3) Insufficient grounds for refusal to serve—The following are not sufficient cause for refusal of service to an applicant:

A. Delinquency in payment for service by a previous occupant of the premises to be served; or

B. Failure to pay the bill of another member at the same address except where the change in identity is made to avoid or evade payment of the Cooperative bill.

Credit Requirements 1) Credit requirements for permanent residential applicants and members—

A. The Cooperative will require an applicant for residential service or an existing residential member to establish and maintain satisfactory credit as a condition of providing service.

i. Establishment of credit shall not relieve any member from complying with the Cooperative’s requirements for prompt payment of bills.

ii. The credit worthiness of spouses established during shared service in the 12 months prior to their divorce will be equally applied to both spouses for 12 months immediately after their divorce.

B. An applicant for residential service or an existing residential member can establish satisfactory credit by:

i. Clearing any unpaid or delinquent balances prior to re-establishing service with the Cooperative; and

ii. Meeting and adhering to the Cooperative’s payment policies and/or payment plan such that:

(a) during the most recent 12 consecutive months of service the member is not late in paying a bill more than once;

(b) the member does not have service disconnected for nonpayment; and (c) the member does not have more than one returned check.

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iii. As an applicant, having been a customer of any electric service provider for the same kind of service within the last two years and not having been delinquent more than once in payment of any such electric utility service account in the most recent 12 consecutive months of service and evidenced by a letter of credit history from the applicant's previous electric service provider.

iv. As an applicant, having a credit risk assessment conducted by the Cooperative or on its behalf and receiving a satisfactory credit risk assessment.

v. If satisfactory credit cannot be established by the residential member using these criteria, the member may be required to pay a deposit pursuant to this section.

2) Credit requirements for non-residential applicants or members —For non-residential service, if an applicant’s or existing member’s credit has not been demonstrated satisfactorily to the Cooperative, the applicant or member may be required to pay a deposit in an amount not to exceed one-sixth of the annual estimated bill. Satisfactory credit may be demonstrated by (a) an applicant or member for a period of 24 consecutive non-residential billings without having service disconnected for nonpayment of a bill and without having been delinquent in the payment of bills more than once or (b) as an applicant, having been a customer of any electric service provider for the same kind of service within the last two years and not having been delinquent more than once in payment of any such electric utility service account in the most recent 24 consecutive months of service and evidenced either by a satisfactory letter of credit history from the applicant's previous electric service provider or by a satisfactory credit risk assessment conducted by the Cooperative or on its behalf.

3) Deposits.

A. An applicant, who has not previously received service from the Cooperative, will be required to

pay a fixed deposit in the amount of $150 for residential service or $300 for non-residential service (i) in the event the applicant fails to provide complete, accurate and verifiable identification information when requested by the Cooperative when applying for electric service or (ii) in the event the applicant fails to either (a)_provide a satisfactory letter of credit history from its previous electric service provider or (b) receive a satisfactory credit risk assessment conducted by the Cooperative or on its behalf..

B. An existing member when applying for additional electric service, will be required to pay a fixed

deposit in the amount of $150 for residential service or $300 for non-residential service, (a) in the event the existing member fails to provide complete, accurate and verifiable identification information when requested by the Cooperative or (b) in the event the member failed to satisfactorily demonstrate to the Cooperative the member's creditworthiness or otherwise demonstrated a previous history of neglect to fulfill membership obligations, such as (but not limited to) paying a bill late more than once during the most recent 12 consecutive months of service, service disconnection for nonpayment, failure to meet obligations under a deferred payment agreement, return of a check for insufficient funds, theft of service, meter tampering, safety code violations or fraud. If the member applying for additional electric service has less than 12 consecutive months of service, that member may provide a satisfactory letter of credit history from its previous electric service provider or have a credit risk assessment conducted by the Cooperative or on its behalf and receive a satisfactory credit risk assessment.

C. An applicant, who previously had service with the Cooperative, or an existing member, each of

whom failed to satisfactorily demonstrate to the Cooperative creditworthiness or otherwise demonstrated a previous history of neglect to fulfill membership obligations may be required to pay a deposit (a) in the amount of $150 for residential service or $300 for non-residential service or (b) in an amount not to exceed one-sixth of the annual estimated bill in the event the applicant

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or member fails to provide complete, accurate and verifiable identification information when requested by the Cooperative.

D. The Cooperative may refuse to provide service to an applicant or member if the requested

deposit is not paid at the initiation of service. The Cooperative may also refuse to reconnect service to an existing member if the requested deposit is not paid upon request.

4) Deposits for temporary or seasonal service and for weekend residences. The Cooperative will require a deposit sufficient to reasonably protect it against the assumed risk for temporary or seasonal service or weekend residences, as long as the policy is applied in a uniform and nondiscriminatory manner. These deposits shall be returned according to guidelines set out in Paragraph 8.

5) Amount of deposit. The total of all deposits from a member or applicant for service shall not exceed

one-sixth of the estimated annual billing; provided however, that for those members or applicants subject to the fixed deposit amount described in Section 3. above, the amount of the deposit shall not be less than the amount of those fixed deposits.

6) Interest on deposits. The Cooperative shall pay interest on any required deposits at an annual rate

at least equal to that set by the Public Utility Commission of Texas on December 1 of the preceding year, pursuant to Texas Utilities Code §183.003 (Vernon 1998) (relating to Rate of Interest). If a deposit is refunded within 30 days of the date of deposit, no interest payment is required. If the Cooperative keeps the deposit more than 30 days, payment of interest shall be made retroactive to the date of deposit.

(A) Payment of the interest to the member shall be made annually or at the time the deposit is

returned or credited to the member's account. (B) The deposit shall cease to draw interest on the date it is returned or credited to the member's

account.

7) Records of deposits.

A. The Cooperative shall keep records to show:

i. (1) the name and address of each depositor;

ii. (2) the amount and date of the deposit; and

iii. (3) each transaction concerning the deposit.

B. The Cooperative shall issue a receipt of deposit to each applicant or member paying a deposit

and shall provide means for a depositor to establish a claim if the receipt is lost. C. The Cooperative shall maintain a record of each unclaimed deposit for at least four years. D. The Cooperative shall make a reasonable effort to return unclaimed deposits.

8) Refunding deposits.

A. If service is not connected, or is disconnected, the Cooperative shall promptly refund the

member's or applicant's deposit plus accrued interest on the balance, if any, in excess of the unpaid bills for service furnished.

B. When the member has paid bills for service for 12 consecutive residential billings or for

24 consecutive non-residential billings without having service disconnected for nonpayment of a

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bill and without having been delinquent in the payment of bills more than once, or has not had more than one returned check, the Cooperative shall promptly refund the deposit plus accrued interest to the member or credit the amount of the deposit and accrued interest to the member’s account. The deposit may be retained if the member (1) does not meet the foregoing refund criteria or (2) failed to provide complete, accurate and verifiable identification information when requested by the Cooperative.

9) Re-establishment of credit—A member whose service has been disconnected for nonpayment of bills or theft of service (meter tampering or bypassing of meter) shall be required, before service is reconnected, to pay all amounts due the Cooperative, including reconnection and other applicable fees, and re-establish credit.

Issuance and Format of Bills: 1) Frequency of bills—The Cooperative will issue bills monthly unless service is provided for a period

less than one month.

2) Bill content—Each member’s bill will include all the following information:

A. The due date of the bill;

B. The number and kind of units metered; or

C. The word “Estimated” prominently displayed to identify an estimated bill.

3) Estimated bills—The Cooperative may submit estimated bills for good cause provided that an actual meter reading is unavailable.

4) Record retention—The Cooperative will maintain monthly billing records for each account for at least three years after the date the bill is mailed. The billing records will contain sufficient data to reconstruct a member’s billing for a given month. Copies of a member’s billing records may be obtained by that member on request.

5) Transfer of delinquent balances—If the member has an outstanding balance due from another account in the same member class, then the Cooperative may transfer that balance to the member’s current account. The delinquent balance and specific account will be identified as such on the bill.

Spanish Language Requirements The Cooperative will provide information in English and Spanish and any other language as the Cooperative deems necessary.

Bill Payment and Adjustments 1) Bill due date—The bill provided to the member will include the payment due date which will not be

less than 16 days after issuance. The issuance date is either the postmark date on the envelope or the date posted to the member’s account on the Cooperative’s web site. A payment is delinquent if not received at the Cooperative by the due date.

2) Late payment processing fee—The Cooperative may assess a $20.00 processing fee to cover costs associated with delinquent notices.

3) Penalty on delinquent bills for non-residential service—A penalty of $20.00 or 6%, whichever is greater, may be charged on a delinquent commercial or industrial bill. The 6% penalty on delinquent bills will not be applied to any balance to which the penalty has already been applied.

4) Bill adjustments—If charges are found to be higher or lower than authorized in the Cooperative’s tariffs, then the member’s bill should be corrected.

A. The correction should be made for the entire period for overbilling.

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B. The correction may be made for up to 12 months for underbilling.

5) Disputed bills—

A. If there is a dispute between a member and the Cooperative about a bill for service, the Cooperative will investigate and report the results to the member. If the dispute is not resolved, the Cooperative will inform the member of the complaint procedures outlined in the rule entitled Complaints.

B. If the member files a complaint with the Cooperative, a member's service will not be disconnected for nonpayment of the disputed portion of the bill before the Cooperative completes its supervisory review and informs the member of its determination.

C. The member is obligated to pay any billings not disputed and not under review.

6) Notice of alternate payment programs or payment assistance—When a member contacts the Cooperative and indicates inability to pay a bill or a need for assistance with the bill payment, the Cooperative will inform the member of alternative payment and payment assistance programs.

7) Deferred payment plans—A deferred payment plan is any written arrangement between the Cooperative and a residential member that allows a member to pay an outstanding bill in installments that extend beyond the due date of the next bill. A deferred payment plan may be established in person or by telephone, and all deferred payment plans will be put in writing.

A. The Cooperative may offer a deferred payment plan to any residential member who has expressed an inability to pay and meets the criteria specified in the Cooperative's Tariff.

B. Every deferred payment plan will provide that the delinquent amount may be paid in negotiable installments.

C. Every deferred payment plan offered by the Cooperative:

i. Will state in boldface type the following: “If you are not satisfied with this agreement or if agreement was made by telephone, and you feel this document does not reflect your understanding of that agreement, contact the Cooperative immediately. If you do not contact the Cooperative, you may give up your right to dispute the amount due under the agreement except for the Cooperative's failure or refusal to comply with the terms of this agreement.”;

ii. Will state the length of time covered by the plan;

iii. Will state the total amount to be paid under the plan;

iv. Will state the specific amount of each installment;

v. Will allow the Cooperative to disconnect service if the member does not fulfill the terms of the deferred payment plan, and will state the terms for disconnection;

vi. Will be provided to the member;

vii. Should allow either the member or the Cooperative to initiate a renegotiation of the deferred payment plan if the member's circumstances change substantially during the time of the deferred payment plan; and

viii. Should be limited to one deferred agreement per year.

D. The Cooperative may decline to offer this plan if, in the Cooperative’s judgment, the member is lacking sufficient credit or satisfactory history to warrant further extension of credit or if the member has failed to provide complete, accurate and verifiable identification information when requested by the Cooperative.

8) Fixed Payment Plan – This plan allows a member to pay a fixed amount per month based on twelve

months usage plus 10 percent divided by 12. A true-up and recalculation will be required no more than every 12 months. This plan is applicable to the Residential and Farm/Ranch and Water Well

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rates only. Members may enroll anytime with participation beginning with the first bill rendered after enrollment. Members who select this plan along with an automatic payment option will receive a discount on the first payment under the plan as follows: a) A 10% discount if member selects automatic bank draft, or b) A 5% discount if the member selects automatic credit card payment. The discount will only apply one time for the life of the account. The plan may be cancelled by either the member or the Cooperative upon notification to the other party. Upon cancellation the accumulated balance of the member’s account shall become due and payable. The Cooperative may decline to offer the Fixed Payment Plan if, in the Cooperative’s judgment, the member is lacking sufficient credit or satisfactory history to warrant payment plans or if the member has failed to provide complete, accurate and verifiable identification information when requested by the Cooperative.

9) Average Payment Plan – Under this plan, the member’s monthly payment is the rolling 12 months

average. This plan is applicable to the Residential and Farm/Ranch and Water Well rates only. Members may enroll anytime with participation beginning with the first bill rendered after enrollment. Members who select this plan along with an automatic payment option will receive a discount on the first payment under the plan as follows: a) A 10% discount if member selects automatic bank draft, or b) A 5% discount if the member selects automatic credit card payment. The discount will only apply one time for the life of the account. The plan may be cancelled by either the member or the Cooperative upon notification to the other party. Upon cancellation the accumulated balance of the member’s account shall become due and payable. The Cooperative may decline to offer the Average Payment Plan if, in the Cooperative’s judgment, the member is lacking sufficient credit or satisfactory history to warrant payment plans or if the member has failed to provide complete, accurate and verifiable identification information when requested by the Cooperative.

10) Credit Card Payment Plan—The credit card payment plan allows residential members to pay their utility bills with an accepted credit card using one of the following options:

A. To pay automatically, a member can make arrangements by contacting a Cooperative

representative and requesting a payment plan be set up, or B. To pay as needed, a member can contact a Cooperative representative and initiate the payment

transaction. The member will need to indicate the amount of the payment and provide necessary credit card information and authorization.

11) Bank Draft Payment Plan—The bank draft payment plan allows members to authorize the Cooperative to draft their checking accounts monthly. The amount drafted will be for:

A. The current bill due, or B. The payment due as agreed on the Deferred Agreement. The member’s checking account will be drafted automatically on the bill due date or on the due date of the Deferred Agreement contract.

12) Refunds—Upon closure of an account, the account holder will be issued a refund check for credit balances of $5.00 or more. Refunds on credit balances of less than $5.00 will only be issued upon verbal request of the account holder. Any amounts not refunded will be transferred at the end of the calendar year to the Cooperative’s county assistance program.

Disconnection of Service 1) Disconnection policy—If the Cooperative chooses to disconnect a member, it will follow its Tariff

and the procedures below, or modify them in ways that are more favorable to the member.

2) Disconnection with notice—Service may be disconnected after proper notice for any of these reasons:

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A. Failure to pay a bill for Cooperative services or make deferred payment arrangements by the date of disconnection;

B. Failure to comply with the terms of any payment agreement;

C. Failure to pay a deposit when required;

D. Violation of the Cooperative’s rules on using service in a manner which interferes with the service of others or the operation of nonstandard equipment, if a reasonable attempt has been made to notify the member and the member is provided with a reasonable opportunity to remedy the situation; or

E. Paying a delinquent account balance with a check returned to the Cooperative for insufficient funds.

3) Disconnection without prior notice—Service may be disconnected without prior notice for any of the following reasons:

A. Where a known dangerous condition exists. Where reasonable, given the nature of the hazardous condition, the Cooperative should post a notice of disconnection and the reason for the disconnection at the place of common entry or upon the front door of each affected residential unit as soon as possible after service has been disconnected;

B. Where service is connected without authority;

C. Where service was reconnected without authority after termination for nonpayment; or

D. Where there has been tampering with the Cooperative's equipment or evidence of theft of service.

4) Disconnection prohibited—Service may not be disconnected for any of the following reasons:

A. Delinquency in payment for the Cooperative’s service by a previous occupant of the premises;

B. Failure to pay disputed charges, except for the required average billing payment, until a determination as to the accuracy of the charges has been made by the Cooperative and the member has been notified of this determination; or

C. Failure to pay charges arising from an underbilling due to any faulty metering, unless the meter has been tampered with or unless such underbilling charges as referenced in rule entitled Meter Tampering.

5) Disconnection due to Cooperative abandonment—The Cooperative will not abandon a member or a certified service area without written notice to its members and all similar neighboring utilities, and approval from the Commission.

6) Disconnection of energy assistance clients—The Cooperative cannot terminate service to a delinquent residential member for a billing period in which the Cooperative receives a pledge, letter of intent, purchase order, or other notification that the energy assistance provider is forwarding sufficient payment to continue service.

7) Disconnection during extreme weather—The Cooperative will not disconnect a residential member on a day when:

A. The previous day’s highest temperature did not exceed 32 degrees Fahrenheit, or the temperature is predicted to be at or below that level for the next 24 hours, according to the local National Weather Service (NWS) reports for the designated territory; or

B. The NWS issues a heat advisory for any county in the relevant service territory, or when such an advisory has been issued on any one of the previous two calendar days

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8) Disconnection during weekend. The Cooperative will not disconnect a residential member on a weekend day.

9) Disconnection of master-metered utilities—When a bill for Cooperative services is delinquent for a master-metered utility:

A. The Cooperative should send a notice to the member as required. At the time such notice is issued, the Cooperative should also inform the member that notice of possible disconnection will be provided to the utility’s members in three days if payment is not made before that time.

B. At least three days after providing notice to the member and at least four days before disconnecting, the Cooperative should post a minimum of five notices in conspicuous areas of the utility or other public places. Language in the notice should be in large type and should read: “Notice to members of (name and address of the utility): the Cooperative’s service to this utility is scheduled for disconnection on (date), because (reason for disconnection).”

10) Disconnection notices—Any disconnection notice issued by the Cooperative to a member will:

A. Not be issued before the first day after the bill is due, to enable the Cooperative to determine whether the payment was received by the due date.

B. Be a separate mailing or hand delivered with a stated date of disconnection with the words “disconnection notice” or similar language prominently displayed.

C. Have a disconnection date that is not less than seven days after the notice is issued.

D. Be in English and in Spanish.

E. Include a statement notifying the member that if they need assistance paying their bill by the due date, or are ill and unable to pay their bill, they may be able to make some alternate payment arrangement, establish a deferred payment plan, or possibly secure payment assistance. The notice will also advise the member to contact the Cooperative for more information.

Complaints Complaints to the Cooperative—A member or applicant may file a complaint in person, by letter, or by telephone with the Cooperative regarding rates, service, or other issues.

1) If a complaint cannot immediately be resolved by the employee receiving the complaint, the information collected by the employee will be forwarded to a supervisor or manager. The supervisor or manager will review the complaint and related information, and the complainant will be advised of the results within five working days of the complaint.

2) Service should not be disconnected before completion of the review. If the member chooses not to participate in a review then the Cooperative may disconnect service, providing proper notice has been issued under the disconnect procedures.

3) Members who are dissatisfied with the supervisory-level review will be informed of their right to file a written complaint with either PEC’s General Manager or Assistant General Manager. Under their direction, a three-member management team will review the complaint and the complainant will be advised of the results within ten days of the complaint.

Information to Applicants and Members 1) Information regarding rate schedules and classifications and the Cooperative's facilities—

A. The Cooperative will notify members affected by a change in rates or schedule of classifications.

B. The Cooperative will maintain copies of its rate schedules and rules in each office where applications are received and such copies are available for inspection.

C. The Cooperative will maintain maps showing the physical locations of its facilities that includes an accurate description of all facilities (substations, transmission lines, etc.). Each business office or

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service center will have available maps, plans, or records of its immediate service area, with other information as may be necessary to enable the Cooperative to advise applicants, and others entitled to the information, about the facilities serving that locality.

2) Membership fees—

Membership in the Cooperative is required for service. A membership fee will be required with the initial application for service. Membership fees will be set by the Cooperative’s Board of Directors and shall be held until the last service connection for a member is terminated. The membership fee will be held in the initial account until that account is terminated. At that time the membership fee will be applied to member’s open account or applied to the outstanding account balance of the last open account. Additional fees may be required for each additional service connection requested by the member, but no further membership fee shall be charged and no additional memberships shall be created by the creation of additional service connections by the member. Each legal or natural person or husband and wife pair that is a member of the cooperative shall be entitled to a single membership, no matter how many meters that member has. Refunds on credit balances of less than $5.00 will be issued only upon verbal request of the account holder. Any amounts not refunded will be transferred at the end of the calendar year to the Cooperative’s Member Service Assistance Program.

3) Member information packets—

A. General information about the Cooperative will be accessible online to all new members or as requested.

B. This general information will include the following topics:

i. Services, fees, deposits, and rates;

ii. Payment options;

iii. Conditions of service;

iv. Electrical safety;

v. Power interruptions; and;

vi. A toll-free telephone number to conduct business or to obtain the hours, addresses, and telephone numbers of the Cooperative’s office locations.

4) Member voting—

Each member who is receiving service from the Cooperative shall be entitled to one (1) vote upon each matter submitted to a vote at a meeting of the members. At all meetings of the members at which a quorum is present, all questions shall be decided by a vote of a majority of the members voting thereon in person, by mail, or, when the option is made available to members, electronically, except as otherwise provided by law, the Articles of Incorporation of the Cooperative, or the Bylaws.

Member Access to Cooperative Records A Member, on written request, is entitled to examine and copy (at the member's expense), at any reasonable time, the books and records of the PEC.

Requests for information are restricted to Members of PEC, and the Cooperative reserves the right to charge a fee to the Member, payable in part or wholly in advance, if fulfilling the request will require large amounts of employee time.

Most of the information collected, assembled, or maintained in connection with the transaction of PEC business is available to Members, with a few exceptions. Inspection of certain records may be limited or denied in cases including: privacy, attorney-client privilege; real estate subject matter, personnel subject matter, security; or, matters that are clearly competitive, when the Board of Directors determines in good faith that disclosure presents a compelling risk of likely harm to the Cooperative or its members.

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This policy does not cover material that is requested as part of a legal proceeding.

All Member requests for information should be directed to: Open Records Request, Pedernales Electric Cooperative, Inc., P.O. Box 1, Johnson City, TX 78636.

Reliability and Continuity of Service 1) General—

A. The Cooperative will make all reasonable efforts to prevent interruptions of service. When interruptions occur, the Cooperative will re-establish service within the shortest possible time.

B. The Cooperative endeavors to provide continuous electric service but makes no guarantees against interruptions. If continuous service at a constant voltage is required, the member must install the necessary equipment. Should members require three-phase service, they shall be responsible for providing and operating such protective equipment as is necessary to protect their equipment from damage resulting from loss of power to one or more phases. If electric service is interrupted, the member must determine if the equipment and wiring is functioning properly. Cooperative personnel will not make repairs to members’ wiring or equipment.

C. The Cooperative shall not be liable for damages occasioned by interruption, failure to commence delivery, or voltage, wave form, or frequency fluctuation caused by interruption or failure of service or delay in commencing service due to accident to or breakdown of plant, lines, or equipment, strike, riot, act of God, order of any court or judge granted in any bonafide adverse legal proceedings or action or any order of any commission or tribunal having jurisdiction; or, without limitation by the preceding enumeration, any other act or things due to causes beyond its control, to the negligence of the Cooperative, its employee, or contractors, except to the extent that the damages are occasioned by the gross negligence or willful misconduct of the Cooperative.

D. The Cooperative will make reasonable provisions to manage emergencies resulting from failure of service, and will issue instructions to its employees covering procedures to be followed in the event of emergency in order to prevent or mitigate interruption or impairment of service.

E. In the event of national emergency or local disaster resulting in disruption of normal service, the Cooperative may, in the public interest, interrupt service to other members to provide necessary service to civil defense or other emergency service entities on a temporary basis until normal service to these agencies can be restored.

2) Record of interruption—The Cooperative will keep complete records of sustained interruptions. Where practical, the Cooperative will keep a complete record of all momentary interruptions. These records will show the type of interruption, the cause for the interruption, the date and time of the interruption, the duration of the interruption, the number of members interrupted, the substation identifier, and the transmission line or distribution feeder identifier. The Cooperative will retain records of interruptions for five years.

3) Notice of significant interruptions—

A. Significant Interruptions—All interruptions of any classification lasting one hour or more and affecting the entire system, a major division of the system, a community, essential services, service to interruptible members, scheduled interruptions lasting more than four hours that affect members that are not notified in advance, 20% or more of the system’s members, or 20,000 members for utilities serving more than 200,000 members. Significant interruptions also include interruptions adversely affecting a community such as interruptions of governmental agencies, military bases, universities and schools, major retail centers, and major employers.

B. Initial notice—Employees will notify the General Manager in a method prescribed by the General Manager as soon as reasonably possible after it has determined that a significant interruption has occurred. The initial notice will include the general location of the significant interruption, the approximate number of members affected, the cause if known, the time of the event, and the

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estimated time of full restoration. If the duration of the significant interruption is greater than 24 hours, the Cooperative will update this information daily and file a summary report.

C. Summary report—Within three working days after the end of a significant interruption lasting more than 24 hours, a summary report should be submitted to the General Manager. The summary report will include the date and time of the significant interruption; the date and time of full restoration; the cause of the interruption, the location, substation and feeder identifiers of all affected facilities; the total number of members affected; the dates, times, and numbers of members affected by partial or step restoration; and the total number of member-minutes of the significant interruption (sum of the interruption durations times the number of members affected).

4) Emergency Operations Plan—The Cooperative will maintain a general description of its emergency operations plan. The Cooperative’s emergency plan will include, but need not be limited to, the following:

A. A registry of essential services directly served by the Cooperative. This registry will be updated as necessary but not less often than annually. The description will include the location of the registry, how the Cooperative ensures that it is maintaining an accurate registry, how the Cooperative will provide assistance to essential services members in the event of an unplanned outage, how the Cooperative intends to communicate with the essential services members, and how the Cooperative is training its staff with respect to serving critical members and loads.

B. A communications plan that describes the procedures for contacting the media and members and essential services directly served by the Cooperative as soon as reasonably possible, either before or at the onset of the emergency. The communications plan will also address how the Cooperative’s telephone system and complaint handling procedures will be augmented during an emergency, and;

C. Priorities for restoration of service.

Meter Requirements 1) Use of meter—All electricity consumed or demanded by the member will be charged for by meter

measurements, except where otherwise provided for by the applicable rate schedule or contract.

2) Installation—The Cooperative will provide, install, own, and maintain all meters necessary for the measurement of electric energy to its members.

3) Standard type—All meters will meet industry standards. Special meters used for investigation or experimental purposes are not required to conform to these standards.

4) Location of meters—

A. Meters and service switches in conjunction with the meter will be installed in accordance with the latest revision of American National Standards Institute (ANSI), Incorporated, Standard C12 (American National Code for Electricity Metering), and will be readily accessible for reading, testing, and inspection, where such activities will cause minimum interference and inconvenience to the member.

B. Member will provide, without cost to the Cooperative, at a suitable and easily accessible location:

i. Sufficient and proper space for installation of meters and other apparatus of the Cooperative;

ii. Meter board;

iii. Meter loop;

iv. Safety service switches when required; and

v. An adequate anchor for service drops.

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C. Where the meter location on the member’s premises is changed at the request of the member, or due to alterations on the member’s premises, the member will provide and have installed at their expense, all wiring and equipment necessary for relocating the meter.

5) Accuracy requirements—

A. No meter that violates the test calibration limits as set by the American National Standards Institute, Incorporated will be placed in service or left in service. Whenever on installation, periodic, or other tests, a meter is found to violate these limits, it will be adjusted.

B. Meters will be adjusted as closely as practicable to the condition of zero error.

Meter Records The Cooperative will keep the following records:

1) Meter equipment record—The Cooperative will keep a record of all of its meters, showing the member’s address and date of the last test. For special meters used for investigation or experimental purposes, the record will state the purpose of the investigation or experiment.

2) Records of meter tests—All meter tests will be properly referenced to the meter record provided in this section. The record of each test made on member’s premises or on request of a member will show the identifying number and constants of the meter, the standard meter and other measuring devices used, the date and kind of test made, who conducted the test, the error (or percentage of accuracy) at each load tested, and sufficient data to permit verification of all calculations.

Meter Readings Each meter should clearly indicate the units of service for which charge is made to the member. Meters shall be read at regular monthly intervals.

Meter Testing 1) Meter tests prior to installation—No permanently installed meter should be placed in service

unless its accuracy has been established. If any permanently installed meter is removed from actual service and replaced by another meter for any purpose, it should be properly tested and adjusted before being placed back in service unless such meter has been tested in the last 12 months.

2) Testing of meters in service—Meter test periods for all types of meters will conform to the latest edition of American National Standards Institute, Incorporated (ANSI) Standard C12 unless specified otherwise by the Cooperative.

3) Meter tests on request of member—

A. The Cooperative will, upon the request of a member, test the accuracy of the member’s meter.

B. If the meter has been tested by the Cooperative, or by an authorized agency, at the member’s request, and within a period of four years the member requests a new test, the Cooperative will make the test.

C. Following the completion of any requested test, the Cooperative will advise the member of the date of removal of the meter, the date of the test, the result of the test, and who made the test.

Adjustments Due to Meter Errors 1) If any meter is found to be not in compliance with the accuracy standards, readings will be corrected

and adjusted bills may be rendered.

2) No refund is required from the Cooperative except to the member last served by the meter prior to the testing.

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3) If a meter is found not to register for any period, unless bypassed or tampered with, the Cooperative should estimate and charge for units used, but not metered. The estimated charge should be based on amounts used under similar conditions during the period preceding or subsequent to the period the meter was found not to register, or during corresponding periods in previous years.

Meter Tampering Meter tampering, bypass, or diversion will be defined as tampering with the Cooperative's meter or equipment, bypassing the same, or other instances of diversion, such as physically disorienting the meter; attaching objects to the meter to divert or bypass service; inserting objects into the meter; and other electrical and mechanical means of tampering with, bypassing, or diverting electrical service. Meter tampering is a criminal offense.

Interconnection Meters and Circuit Breakers The Cooperative should ensure that all instruments and meters are maintained as may be necessary to obtain full information as to purchases, unless this information is metered and furnished by the electric utility supplying the energy. Any interconnection with the Cooperative must be in accordance with the Cooperative’s Small Power Producer Interconnection Policy and only after execution of the Cooperative’s Agreement for Interconnection.

Member Service Option The following optional service is available to members:

Service Monitoring – This service is available for a fee of $7.50 per month. The Cooperative will monitor the member’s meter once a day and will notify the member or a designee if the power appears to be out on the member’s side of the meter. The Cooperative cannot guarantee the exact nature of the suspected outage, but can only detect and inform the member of a zero usage read on the member’s side of the meter.

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Adopted 12-20-2010

Tariff

For Electric Service Provided by


201 South Avenue F P.O. Box 1

Johnson City, Texas 78636-0001

Adopted 12-20-2010

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PEDERNALES ELECTRIC COOPERATIVE, INC. TARIFF

Adopted 12-20-2010

TABLE OF CONTENTS

100 RATE SCHEDULES.................................................................................................................................................................4

GENERAL PROVISIONS ...........................................................................................................................................................................4 100.1 RESIDENTIAL AND FARM/RANCH (R)..................................................................................................................................4 100.2 WATER WELL (W)..............................................................................................................................................................5 100.3 SMALL POWER (SP) ............................................................................................................................................................5 100.4 LARGE POWER (LP) ............................................................................................................................................................5 100.5 INDUSTRIAL POWER (IP).....................................................................................................................................................6 100.6 POWER PLANT START POWER (PPSP) ................................................................................................................................6 100.7 INTERCONNECTION BACK-UP (IB) ......................................................................................................................................7 100.8 GREEN POWER (GP) (DISCONTINUED 10-17-2005) .............................................................................................................7 100.9 RENEWABLE POWER (RP)...................................................................................................................................................7 100.10 COLLEGE DISCOUNT RIDER (CDR).....................................................................................................................................7 100.11 AREA LIGHTING (AL) .........................................................................................................................................................8 100.12 INTERRUPTIBLE SERVICE RIDER (ISR) (DISCONTINUED AFTER 06-15-2009).......................................................................8 100.13 POWER COST RECOVERY (PCR) .......................................................................................................................................10 100.14 WHOLESALE TRANSMISSION POLICY (WTS) ....................................................................................................................11 100.15 WHOLESALE DISTRIBUTION SERVICE (WDS) ...................................................................................................................12

200 SERVICE POLICY.................................................................................................................................................................15

200.1 CONDITION OF SERVICE ....................................................................................................................................................15 200.2 MEMBERSHIP FEE .............................................................................................................................................................15 200.3 ESTABLISHMENT FEE ........................................................................................................................................................15 200.4 SAME DAY SERVICE FEE...................................................................................................................................................15 200.5 SERVICE TO RENTAL LOCATIONS......................................................................................................................................16 200.6 REAL ESTATE SHOW FEE ..................................................................................................................................................16 200.7 CONTINUITY OF SERVICE ..................................................................................................................................................16 200.8 SERVICE MONITORING......................................................................................................................................................16 200.9 METER TAMPERING ..........................................................................................................................................................16 200.10 BILLING ............................................................................................................................................................................16 200.11 UNDERBILLING .................................................................................................................................................................17 200.12 PAYMENT..........................................................................................................................................................................17 200.13 PAYMENT OPTIONS...........................................................................................................................................................17 200.14 INTERCONNECTION ...........................................................................................................................................................18 200.15 DISCONNECTION OF SERVICE............................................................................................................................................18 200.16 RECONNECTION FEE .........................................................................................................................................................18 200.17 DISPUTED BILLS ...............................................................................................................................................................18 200.18 MEMBER COMPLAINTS .....................................................................................................................................................19 200.19 RETURNED CHECK/DENIED BANK DRAFT/DENIED CREDIT CARD....................................................................................19 200.20 MEMBER VOTING .............................................................................................................................................................19 200.21 MEMBER ACCESS TO COOPERATIVE RECORDS .................................................................................................................19 200.22 ACCOUNT RESEARCH SERVICES .......................................................................................................................................19 200.23 EASEMENT RELEASE.........................................................................................................................................................19 200.24 SWITCHOVER POLICY .......................................................................................................................................................20 200.25 STATUS OF THE POLICY ....................................................................................................................................................20 300 LINE EXTENSION POLICY..................................................................................................................................................21 300.1 GENERAL POLICY .............................................................................................................................................................21 300.2 PERMANENT OVERHEAD RESIDENTIAL, FARM, AND RANCH SERVICE ..............................................................................21 300.3 OTHER RESIDENTIAL, FARM, AND RANCH OVERHEAD SERVICE EXTENSIONS..................................................................22 300.4 OTHER OVERHEAD LINE EXTENSIONS ..............................................................................................................................23 300.5 RESIDENTIAL DEVELOPMENTS..........................................................................................................................................24 300.6 COMMERCIAL DEVELOPMENTS.........................................................................................................................................25 300.7 UNDERGROUND SERVICE..................................................................................................................................................26 300.8 TEMPORARY SERVICE.......................................................................................................................................................27

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Adopted 12-20-2010

300.9 AREA LIGHTING................................................................................................................................................................27 300.10 LINE CLEARANCE .............................................................................................................................................................27 300.11 OWNERSHIP OF DISTRIBUTION FACILITIES........................................................................................................................27 300.12 NO REFUND OF AID TO CONSTRUCTION............................................................................................................................27 300.13 RELOCATION OF FACILITIES..............................................................................................................................................27 300.14 FORMULA FOR CALCULATING CONTRIBUTION IN AID OF CONSTRUCTION........................................................................28

400 CREDIT REQUIREMENTS AND DEPOSITS....................................................................................................................28

400.1 CREDIT REQUIREMENTS FOR PERMANENT RESIDENTIAL APPLICANTS AND MEMBERS........................................................28 400.2 CREDIT REQUIREMENTS FOR NON-RESIDENTIAL MEMBERS OR APPLICANTS. .....................................................................29 400.3 DEPOSITS. .........................................................................................................................................................................29 400.4 DEPOSITS FOR TEMPORARY OR SEASONAL SERVICE AND FOR WEEKEND RESIDENCES. ......................................................30 400.5 AMOUNT OF DEPOSIT. .......................................................................................................................................................30 400.6 INTEREST ON DEPOSITS. ....................................................................................................................................................30 400.7 RECORDS OF DEPOSITS......................................................................................................................................................30 400.8 REFUNDING DEPOSITS. ......................................................................................................................................................31 400.9 RE-ESTABLISHMENT OF CREDIT. .......................................................................................................................................31

500 FEE SCHEDULE ....................................................................................................................................................................32

FEE SCHEDULE................................................................................................................................................................................32

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Adopted 12-20-2010 Page 4

100 Rate Schedules

General Provisions

Character of Service - The Cooperative will provide single, open-wye, or three-phase alternating current at one of its standard secondary voltage from existing facilities as described in the Cooperative’s Service Policy.

1. Payment - Rates are subject to the payment policies as provided in the Cooperative’s Service Policy.

2. Sales Taxes - Sales taxes, where applicable, will be charged to the member in addition to the applicable rates. Members claiming exemption from sales taxes should provide an exemption form acceptable to the Cooperative.

3. Late Payment Processing Fee - The Cooperative may assess a $20.00 processing fee to cover costs associated

with delinquent notices. Bills to all non-residential accounts other than state agencies, may be assessed a Late Payment Processing Fee of $20.00 or 6% of the unpaid balance, whichever is greater, if not paid by the due date.

4. Point of Delivery - The Point of Delivery is that point, as determined by Cooperative, where the electric power and

energy leaves the Cooperative electric delivery system and is delivered to member.

5. Single Point Delivery - Rates are based upon service to the entire premises through a single delivery and metering point. Service to the same member at other points of delivery shall be separately metered and billed under the applicable rate schedule.

6. Standard Voltage Designations – The Cooperative adopts the following standard voltages for distribution:

Single Phase Three Phase

120/240 V 120/208 V (wye)

*7200 V *120/240 V (delta)

*14400 V 277/480 V (wye)

*480V (delta)

*1328/2300 V (wye)

*2300/4160V (wye)

*7200/12470 V (Primary Metered)

*14400/24900 V (Primary Metered) *These voltages are available at Cooperatives discretion. These voltage designations are nominal design voltages and the actual normal delivery voltages so far as practicable will be maintained within variations permitted by industry standards. Member should obtain from the Cooperative the phase and voltage of the service available before committing to the purchase of motors or other equipment.

7. Power Factor Adjustment - (Large Power and Industrial Power) – Capacity delivery charges may be adjusted if the power factor is lower than ninety-seven percent (97%). Measured capacity (KW) may be increased by one percent (1%) for each one percent (1%) by which the power factor is less than ninety-seven percent (97%) lagging for a period of fifteen (15) consecutive minutes.

100.1 Residential and Farm/Ranch (R)

Applicability - Applicable to individually metered residences, farms, ranches, and their facilities. Rates Service Availability Charge: $22.50 per month

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Delivery Charge: $0.03212 per KWH Base Power Cost: The per kWh base power costs for Power Supply Charges stated in the Power Cost

Recovery (PCR) Tariff Power Cost Adjustment: The charge per kWh for changes in Power Supply Charges relative to the base

power cost and calculated in accordance with the Power Cost Recovery (PCR) Tariff The monthly bill shall be the sum of the above charges plus any applicable fees.

100.2 Water Well (W)

Applicability - Applicable to water wells used solely for small scale agricultural purposes. Agricultural purposes include livestock watering, crop irrigation, and fisheries. Irrigation for recreational purposes is served under other Tariffs. Rates Service Availability Charge: $19.50 per month Delivery Charge: $0.03212 per KWH

Base Power Cost: The per kWh base power costs for Power Supply Charges stated in the Power Cost Recovery (PCR) Tariff

Power Cost Adjustment: The charge per kWh for changes in Power Supply Charges relative to the base


100.3 Small Power (SP)

Applicability - Applicable to all commercial and industrial members whose demand is less than 75 kilowatts and whose use is not covered by another specific rate schedule. Member owned street lighting will also be billed under the Small Power Rate. Rates Service Availability Charge: $37.50 per month Delivery Charge: $0.02488 per KWH




100.4 Large Power (LP)

Applicability - Applicable to all commercial and industrial members whose demand is 75 kilowatts but less than 10,000 kilowatts, and whose use is not covered by another specific rate schedule.

Rates

Service Availability Charge: $150.00 per month

Capacity Delivery Charge: Secondary Level Service $4.00 per kW Primary Level Service $3.92 per kW

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Delivery Charge: Secondary Level Service $0.01048 per KWH

Primary Level Service $0.01027 per KWH



power cost and calculated in accordance with the Power Cost Recovery (PCR) Tariff

The monthly bill shall be the sum of the above charges plus any applicable fees. Secondary Rate – The Secondary Rate per kilowatt-hour shall be provided for those members receiving service at secondary voltages less than 6 kV at locations where the Cooperative owns the transformation facilities.

Primary Rate - Primary Rate per kilowatt-hour shall be provided for high voltage deliveries to the transformer at 6 kV or higher where the member has paid for the transformation facilities or where deliveries to the member are at 6 kV or higher. A delivery point meeting the above criteria shall be charged the Primary Rate whether the delivery is metered on the low side or the high side of the point of transformation. Meter readings from the low side transformation shall be adjusted for transformation losses.

100.5 Industrial Power (IP)

Applicability - Applicable to all commercial and industrial members whose firm demand is 10,000 kilowatts or more, and whose uses are not covered by another specific rate schedule.

Rates Service Availability Charge: $1,000.00 Capacity Delivery Charge: $ 1.00 per kW

Power Supply Charge: The cost of power to serve the member, including capacity, ancillary services, delivery, energy, and fuel charges for the billing period plus adjustments applied to the current monthly billing to account for differences in actual purchased electricity costs billed in previous periods. The power cost will be calculated using billing units defined in the same manner as defined in the Wholesale rate to the Cooperative, including any ratchet provisions in the wholesale rate. The member’s billing units for power cost may be adjusted for line losses, as determined by the Cooperative, to calculate the member’s power cost at the wholesale supplier’s metering point to the Cooperative.

The monthly bill shall be the sum of the above charges plus any applicable fees.

100.6 Power Plant Start Power (PPSP)

Applicability - Applicable to all commercially operated power plants whose firm demand is 1,000 kilowatts or more, and whose uses are not covered by another specific rate schedule.

Rates Service Availability Charge: $1,500.00 per month

Power Supply Charge: The cost of power to serve the member, including capacity, ancillary services, delivery, energy, and fuel charges for the billing period plus adjustments applied to the current monthly billing to account for differences in actual purchased electricity costs billed in previous periods. The power cost will be calculated using billing units defined in the same manner as defined in the Wholesale rate to the Cooperative, including any ratchet provisions in the wholesale rate. The member’s billing units for power cost may be adjusted for line losses, as determined by the Cooperative, to calculate the member’s power cost at the wholesale supplier’s metering point to the Cooperative.

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100.7 Interconnection Back-up (IB)

Applicability - Applicable to members with small power production equipment of less than 20 kW who have executed an agreement for interconnection with the Cooperative. Service shall be through a single meter which measures the net energy consumed at the premises. Rates As per the otherwise applicable tariff with charges other than the Service Availability Charge applied to net energy consumed at the premises.

100.8 Green Power (GP) (discontinued 10-17-2005)

Applicability - Applicable to members choosing to purchase electricity generated by 100% renewable energy sources. Participation is by billing cycle. Changes must be requested at least 5 days prior to the start of the next billing cycle. This rate has been discontinued. However, members receiving service under this rate prior to October 17, 2005 may continue to receive service under this rate at the Cooperative’s discretion. Rates Service Availability Charge: As per the otherwise applicable tariff. Delivery Charge: As per the otherwise applicable tariff (excluding any PCA) plus $0.02 per KWH.

Power Cost Adjustment: The charge per kWh for changes in Power Supply Charges relative to the base power cost and calculated in accordance with the Power Cost Recovery (PCR) Tariff

The monthly bill shall be the Service Availability Charge plus charges at the above rate for energy consumed.

100.9 Renewable Power (RP)

Applicability - Applicable to members choosing to purchase electricity generated by 100% renewable energy sources. Participation is by billing cycle. Changes must be requested at least 5 days prior to the start of the next billing cycle. Rates Service Availability Charge: As per the otherwise applicable tariff. Delivery Charge: As per the otherwise applicable tariff. Base Power Cost: The per kWh base power costs for Power Supply Charges stated in the Power Cost

Recovery (PCR) Tariff for Renewable Power Cost Adjustment: The charge per kWh for changes in Power Supply Charges relative to the base


100.10 College Discount Rider (CDR)

Applicability - Applicable in conjunction with an otherwise applicable rate schedule for electric service to any facility of any four year state university, upper level institution, Texas State Technical College, or college to which the Cooperative is required to discount the base rates, as provided in Texas Utilities Code, §36.351. The provisions of the applicable rate schedule are modified only as shown herein.

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Monthly Rate - In accordance with the terms of the applicable rate schedule, except that the amount due under the applicable rate schedule, minus the cost of purchased electricity applicable to the member and excluding any adjustment factors, cost recovery factors, or specific facilities charges, and service fees, is reduced by 20%.

100.11 Area Lighting (AL)

Applicability - Applicable to outdoor dusk-to-dawn lighting where the Cooperative's existing facilities are suitable for the installation of the lighting. The Cooperative will furnish, install, and maintain lights on existing facilities. If additional facilities are required, the member will pay installation costs. The member will pay for costs of repairs, labor, and materials for damage due to vandalism. The member will also pay for all costs of relocating any light. This rate applies only to Cooperative owned lighting.

Rates

Delivery Charges:

Lamp Size kWh per month Charge

per Lamp

100 Watt Sodium 45 kWh per month $ 8.15

250 Watt Sodium 110 kWh per month $16.30

175 Watt Metal Halide 78 kWh per month $ 8.15

175 Watt Mercury Vapor 75 kWh per month $ 8.15

Base Power Cost: The per kWh base power cost for Power Supply Charges stated in the Power Cost Recovery (PCR) Tariff Power Cost Adjustment: The charge per kWh for changes in Power Supply Charges relative to the base power cost and calculated in accordance with the Power Cost Recovery (PCR) Tariff


100.12 Interruptible Service Rider (ISR) (discontinued after 06-15-2009)

Applicability - This Rider is applicable to members under long-term contract with the Cooperative for firm full-requirement service. A contract must be executed between the Cooperative, the Lower Colorado River Authority (LCRA), and the member establishing the amount of interruptible and firm load to be served. If the member adds new load to its operations after the date of execution of the contract, that new load shall be added to the firm demand portion of the member’s total load unless otherwise mutually agreed upon by the parties. The member’s interruptible load must be separately metered as an additional point of delivery unless mutually agreed upon by the parties. Each member’s interruptible amount must be a minimum load of five megawatts. The member must be able to demonstrate its ability to interrupt its demand within the period set forth in this tariff upon verbal notification by the Cooperative or the LCRA. This Rider contains daily, monthly, and yearly limitations on interruptions imposed by the Cooperative and by the LCRA. The annual limitation will be measured by a continuous, moving, or rolling period of 12 consecutive months, hereinafter sometimes called the Limitation Year. With respect to any one day in which either the Cooperative or the LCRA proposes an interruption, the calendar month in which that day falls shall be the twelfth month of the Limitation Year. Availability - The availability of this Rider shall be limited to members receiving service under this Rider as of the effective date of these tariffs and in the manner set forth in the LCRA’s Interruptible Service Rider to Schedule WP-1 or any successor tariff provision adopted by the LCRA (Interruptible Tariff). The Cooperative may discontinue providing service under this Rider if interruptible wholesale power service is not available to the Cooperative. Rate - The rate for this Rider shall equal the rate established for firm service, except that the rates for this Rider shall be increased or decreased in accordance with the Power Cost Recovery Factor applicable to members for whom

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Power Costs can be directly identified and assigned (PCRFD) as set forth in Schedule PCRF. The Power Cost Recovery Factor applicable to members whose entire load is served under the Industrial Power Rate Schedule or the Interruptible Service Rider Rate Schedule from a wholesale delivery point as the only member receiving service from that wholesale delivery point, Power Cost - Direct, shall be applied to all load served as a single wholesale delivery point by the Cooperative's wholesale power supplier. In the event that additional wholesale power charges result from the member's failure to comply with the request to interrupt by either the Cooperative or the LCRA, any and all costs associated with such failure to comply shall be applied to the billing of the member failing to interrupt service. Interruptions - The LCRA will interrupt service to the Cooperative’s interruptible service member in accordance with the provisions of the LCRA’s Interruptible Tariff. As a standard operating procedure, the LCRA will attempt to give the member 120 minutes verbal notice prior to the commencement of interruption. During unplanned generation outages, unplanned maintenance of a generation unit, and/or when the LCRA has exceeded its Interruptible Threshold, the LCRA will provide at least a 60-minute verbal notice for the interruptible service member to curtail all interruptible capacity. Under extraordinary or emergency conditions, as determined at the discretion of the LCRA, the LCRA may advise the member of such conditions and request an interruption upon a 20-minute verbal notice. The Cooperative does not guarantee or warrant that notice will be provided in the manner and within the time limits set forth above. The Cooperative shall have no liability and the member shall assume full responsibility for any loss, damage, or claim (including, but not limited to product loss and profit loss) by reason of any interruption or restoration of electric service. Limitations on Interruptions - Limitations upon interruptions imposed by the LCRA shall be the limitations set forth in the LCRA’s Interruptible Tariff. Alternate Supply - In the event that the LCRA is unable to supply the Cooperative’s interruptible member’s requirements because of non-ERCOT emergencies, the interruptible member will be given the option of receiving alternative supply choices in accordance with the LCRA’s Interruptible Tariff. The interruptible member shall assume the additional power costs of available short-term power of alternate power supplies. The cost of an alternate supply shall be added to the wholesale power cost calculated using the member's actual contract firm and interruptible service, as set forth above. Non-Compliance - If at any time during the contract period either the Cooperative or the LCRA requests an interruption and the interruptible member does not comply with that request in whole or in part, the member failing to curtail service shall be subject to the Non-Compliance Penalties contained in the LCRA’s Interruptible Tariff. In accordance with the terms and conditions of the LCRA’s Interruptible Tariff, a member’s failure to comply with a request to interrupt service may result in non-compliance penalties or in termination of interruptible service. The member’s total load will be metered and compliance will be measured by determining that the member’s load did not exceed the firm contract amount during the interruption period and calculated as follows:

Non-Compliance Kilowatt Demand = 1) less 2) where:

1 = The maximum total metered kilowatt demand during the interruption duration period. 2 = The firm contract kilowatt demand. This provision shall not apply if the Limitations on Interruptions provisions set forth above are exceeded.

Term - Except as provided in Non-Compliance above, any party to the contract may cancel the interruptible contract upon three years written notice.

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100.13 Power Cost Recovery (PCR)

This tariff is applicable to all rates except Industrial and Power Plant Start Power which have separate provisions for power cost recovery. Base Power Cost – The base power cost per kWh for Power Supply Charges is:

Secondary Level Service: $0.07208 per kWh Primary Level Service: $0.07064 per kWh Secondary Level Service With Renewable: $0.07708 per kWh

Power Cost Adjustment

For all kilowatt-hours sold to members taking service under all rates except Industrial and Power Plant Start Power, the monthly Power Cost Adjustment per kWh will be calculated as follows:

A - B + C

Basic PCA = kWhs

Secondary Level Service PCA = Basic PCA Primary Level Service PCA = Basic PCA x 98%

Wind Power Subscribers = Applicable Secondary Level or Primary Level Service PCA per kWh plus Wind Power Premium per kWh.

Where:

PCA = Power Cost Recovery (expressed in $ per kWh) to be applied to estimated energy sales for the billing period.

A = Total estimated purchased electricity cost (excluding power cost for Industrial and Power Plant Start Power and excluding Wind Power and/or Renewable Power costs applicable to members subscribing to Wind Power and/or Renewable Power) from all suppliers including fuel for the billing period minus $0.005 per kWh of the kWh sold to Renewable Power Members.

B = Total estimated purchased electricity cost (excluding power cost for Industrial and Power Plant Start Power and excluding Wind Power and/or Renewable Power costs applicable to members subscribing to Wind Power and/or Renewable Power) from all suppliers including fuel which are included in the Cooperative's base rates. The base power cost is computed as: B = (D)(kWhs) minus $0.005 per kWh of the kWh sold to Renewable Power

Members. D = Base power cost of $0.07208 per kWh sold

kWhs = Total estimated energy sales for billing period (excluding power cost for Industrial and Power Plant Start Power) minus 2% of the kWh sold for primary level service members.

C = Adjustment to be applied to the current monthly billing to account for differences in actual purchased electricity costs and actual PCA revenues recovered in previous periods.

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100.14 Wholesale Transmission Policy (WTS)

Availability - Planned and Unplanned Wholesale Transmission Service is available at all points where transmission facilities of adequate capacity and suitable voltage are available. Service under this rate schedule is not available until the expiration of the Facilities and Premises Lease and Operating Agreement between the Cooperative and the Lower Colorado River Authority. Applicability - Wholesale Transmission Service is provided to any eligible member as that term is defined in Substantive Rule 25.5 of the Public Utility Commission (PUC), and shall be provided in accordance with Substantive Rules 25.191 and 25.195. Any power delivered onto or received from the Cooperative’s transmission system under this rate schedule must be delivered or received at 60,000 volts or higher, three phase, 60 hertz alternating current, onto transmission lines which have been made available for this service. This rate schedule is applicable to Planned and Unplanned service over any transmission facilities at 60,000 volts or higher owned by the Cooperative. Conditions The Cooperative will provide transmission service to any eligible member, provided that:

• The eligible member has completed an Application for Annual Planned Service, an Application for Monthly Planned Service, or a Request for Unplanned Transmission Service in accordance with the procedural and scheduling requirements of PUC Substantive Rule 25.198;

• If the member has physical connections to the Cooperative system, the eligible member has an

executed Interconnection Agreement for Transmission Service, or has requested in writing that the Cooperative file a proposed unexecuted agreement with the Commission;

• Both the Cooperative and the eligible member (or a designated agent) have completed

installation of all equipment specified under the Interconnection Agreement for Transmission Service;

• The eligible member has arranged for ancillary services necessary for the transaction.

Pricing - Charges for planned and unplanned transmission service shall be in accordance with PUC Substantive Rule 25.192.

Losses - A wholesale transmission eligible member that uses transmission service shall compensate the Cooperative for energy losses resulting from such transmission service. The ERCOT transmission system independent system operator (ISO) under a method approved by the PUC shall calculate losses.

Resale of Transmission Rights - A wholesale transmission eligible member is permitted to resell any and all transmission service rights contracted for by the transmission member to other wholesale market participants, pursuant to PUC Substantive Rule 25.191. The transmission member shall inform the transmission provider and obtain ISO approval for any resale of transmission service rights.

Construction of New Facilities - The Cooperative shall follow the procedures set forth in PUC Substantive Rule 25.198 in working with the transmission member in order to identify required improvements to the transmission system. Upon receipt of a request for transmission service, the Cooperative shall perform a system security study to assess the ability of the existing transmission system to support the requested transmission service. The member requesting such service shall be responsible for the costs of such system security study and any subsequent facilities studies performed in order to determine any necessary system improvements.

In the event that existing facilities are adequate to support the requested transmission service, the transmission member will be assessed an amount equal to the cost of direct assignment facilities less any applicable depreciation. In the event that existing facilities are inadequate to support the requested transmission service, the transmission member may be required to provide a contribution in aid-to-construction of direct assignment facilities. In that event, the Cooperative will provide the eligible member with a facilities study that will include an estimate of the contribution

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in aid-to-construction of direct assignment facilities to be charged to the transmission member for the cost of any required facilities or upgrades, and the time required to complete such construction and initiate the requested service. In the event that new facilities must be constructed to provide the requested transmission service, the transmission member may be required to provide one or more of the following:

• A contribution in aid-to-construction for those facilities required to provide service to the transmission member. This would apply in those cases the required facilities would be of use to the Cooperative after the transmission member terminates service.

• The sum of installation and removal costs for the construction of facilities required for temporary service. This

would apply in those cases where the duration of the service is less than a year and the required facilities would not be of use to the Cooperative after the transmission member terminates service.

• The sum of installation and removal costs for the construction of facilities which would not be of use to the

Cooperative after the transmission member terminates service. Voltage Support - The Cooperative will install whatever devices are necessary to maintain proper operating voltages on the Cooperative transmission system. However, should the need for such devices be directly or partially applicable to the addition of the transmission member, then the cost of such devices will be included in any contribution in aid-to-construction required of that member. Power Factor - Each wholesale transmission member shall maintain a power factor of 97% or greater at each point of interconnection. If the member fails to maintain a 97% power factor, Pedernales Electric Cooperative will make the necessary improvements and shall charge the member for the costs of such improvements. Reliability Guidelines - To maintain reliability of the ERCOT transmission grid, the Cooperative or other designated agent or representative shall operate its transmission system in accordance with the ERCOT Operating Guides, National Electric Reliability Council (NERC) guidelines, and any guidelines of the ISO that may apply to the Cooperative’s system.

Payment - Any charges due to the Cooperative under this rate schedule shall be billed in accordance with PUC Substantive Rule 25.202. The eligible member shall make payment to the Cooperative in a manner consistent with the procedures and deadlines set forth in PUC Substantive Rule 25.202. Any late payments by member or member default shall be handled in accordance with PUC Substantive Rule 25.202. Contract Term - Planned transmission service is available in multiples of one month. Planned transmission service for a period of less than 12 months shall be considered temporary. Unplanned transmission service may be available for periods of not less than one hour or more than 30 days.

100.15 Wholesale Distribution Service (WDS)

Availability - Planned and Unplanned Wholesale Distribution Service is available at all points where distribution facilities of adequate capacity and suitable voltage are available. Applicability - Wholesale Distribution Service is provided to any eligible member as that term is defined in Substantive Rule 25.5 of the Public Utility Commission (PUC), and shall be provided in accordance with Substantive Rules 25.191 and 25.195. Any power delivered onto or received from the Cooperative’s distribution system under this rate schedule must be delivered or received at less than 60,000 volts, three phase, 60 hertz alternating current, onto distribution lines which have been made available for this service. This rate schedule is applicable to Planned and Unplanned service over any distribution facilities at less than 60,000 volts owned by the Cooperative. This rate schedule is applicable in addition to the Cooperative’s Wholesale Transmission Service rate schedule.

Conditions The Cooperative will provide distribution service to any eligible member, provided that:

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• The eligible member has completed an Application for Annual Planned Service, an Application for Monthly Planned Service, or a Request for Unplanned Distribution Service in accordance with the procedural and scheduling requirements of PUC Substantive Rule 25.198;

• If the member has physical connections to the Cooperative system, the eligible member has an

executed Interconnection Agreement for Distribution Service, or has requested in writing that the Cooperative file a proposed unexecuted agreement with the Commission;

• Both the Cooperative and the distribution member (or a designated agent) have completed

installation of all equipment specified under the Interconnection Agreement for Distribution Service;

• The eligible member has arranged for ancillary services necessary for the transaction.

Pricing

Charges for planned and unplanned wholesale distribution service shall be in accordance with PUC Substantive Rule 25.192. Charges for Wholesale Distribution Service are applicable in addition to any charges for Wholesale Transmission Service that may also be required by the member. Charges for planned Wholesale Distribution Service shall be computed as follows:

INV x FRC = WDSC

where, INV = The investment necessary to provide Wholesale Distribution Service while maintaining the reliability,

voltage, safety, and economic operation of the Cooperative’s system. This investment amount will be recalculated from time to time at the discretion of the Cooperative to reflect any changes in the value of the facilities investment.

FRC = The Cooperative’s monthly fixed rate charge as it may change from time to time as determined by

the Cooperative. The monthly fixed rate charge factor for Cooperative-owned facilities for which no contribution in aid-to-construction has been made by the member shall include a capital cost component. The monthly fixed rate charge factor for Cooperative-owned facilities for which the member has made a contribution in aid-to-construction shall not include a capital cost component.

WDSC = The monthly charge for Wholesale Distribution Service.

Charges for unplanned Wholesale Distribution Service shall be sufficient to ensure the recovery of losses.

Losses - A Wholesale Distribution eligible member that uses distribution service shall compensate the Cooperative for energy losses resulting from such distribution service. Losses shall be calculated by the ERCOT distribution system independent system operator (ISO) under a method approved by the Public Utility Commission, or by the Cooperative if the ISO does not provide losses for a distribution transaction of the nature requested by the member. Resale of Distribution Rights - A Wholesale Distribution eligible member is permitted to resell any and all distribution service rights contracted for by the distribution member to other wholesale market participants, pursuant to PUC Substantive Rule 25.191. The distribution member shall inform the distribution provider and obtain ISO approval for any resale of distribution service rights. Construction of New Facilities - The Cooperative shall follow the procedures set forth in PUC Substantive Rule 25.198 in working with the distribution member in order to identify required improvements to the distribution system. Upon receipt of a request for distribution service, the Cooperative shall perform a system security study to support the requested distribution service. The member requesting such service shall be responsible for the costs of such system security study and any subsequent facilities studies performed in order to determine any necessary system improvements. In the event that existing facilities are adequate to support the requested distribution service, service will be priced in accordance with Pricing above.

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In the event that existing facilities are inadequate to support the requested distribution service, the distribution member may be required to provide a contribution in aid-to-construction of direct assignment facilities. In that event, the Cooperative will provide the eligible member with a facilities study that will include an estimate of the contribution in aid-to-construction of direct assignment facilities to be charged to the distribution member for the cost of any required facilities of upgrades, and the time required to complete such construction and initiate the requested service. In the event that new facilities must be constructed to provide the requested distribution service, the distribution member may be required to provide one or more of the following:

• A contribution in aid-to-construction for those facilities required to provide service to the distribution member. This would apply in those cases the required facilities would be of use to the Cooperative after the distribution member terminates service.

• The sum of installation and removal costs for the construction of facilities required for temporary service. This

would apply in those cases where the duration of the service is less than a year and the required facilities would not be of use to the Cooperative after the distribution member terminates service.

• The sum of installation and removal costs for the construction of facilities which would not be of use to the Cooperative after the distribution member terminates service.

Voltage Support - The Cooperative will install devices as necessary to maintain proper operating voltages on the Cooperative distribution system. However, should the need for such devices be directly or partially attributable to the addition of the distribution member, then the cost of such devices will be included in any contribution in aid-to-construction required of that member. Power Factor - Each wholesale distribution member shall maintain a power factor of 97% or greater at each point of interconnection. If the member fails to maintain a 97% power factor, Pedernales Electric Cooperative will make the necessary improvements and shall charge the member for the costs of such improvements. Reliability Guidelines - To maintain reliability of the ERCOT transmission grid and/or the Cooperative’s distribution system, the Cooperative, or its designated agent or representative, shall operate the Cooperative’s distribution system in accordance with the ERCOT Operating Guides, National Electric Reliability Council (NERC) guidelines, any guidelines of the ISO that may apply to the Cooperative’s system, and the distribution planning criteria of the LCRA Association of Wholesale Members Power Supply and Transmission Planning Committee published in 1992. Payment - Any charges due to the Cooperative under this rate schedule shall be billed in accordance with PUC Substantive Rule 25.202. The eligible member shall make payment to the Cooperative in a manner consistent with the procedures and deadlines set forth in PUC Substantive Rule 25.202. Any late payments by member or member default shall be handled in accordance with PUC Substantive Rule 25.202. Contract Term - Planned distribution service is available in multiples of one month. Planned distribution service for a period of less than 12 months shall be considered temporary. Unplanned distribution service is available for periods of not less than one hour or more than 30 days.

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200 Service Policy

200.1 Condition of Service

The Cooperative’s Service Policy applies to all locations within its service area, according to the type of service delivered and subject to the provisions of the Cooperative’s rates and Line Extension Policy.

The Cooperative will provide electric service to all applicants within its service area, provided the following conditions are met:

• The applicant pays a membership fee and any other amounts, including any deposits, required by the

Cooperative’s rules, including amounts required by the Credit Requirements and Deposits Policy. • The applicant is not delinquent on a past or present account. • The applicant accepts the terms for membership and rules for service, and provides the Cooperative with

information reasonably required to verify the identity of the applicant. • The applicant grants the Cooperative easement rights and acquires all necessary easements from adjacent

landowners on a form acceptable to the Cooperative for its facilities. All costs and expenses, if any, related to the acquisition of easements to serve the applicant shall be the responsibility of the applicant, including the Cooperative’s costs and expenses if the Cooperative participates in the acquisition of the easements through condemnation proceedings.

• Service can be supplied from existing Cooperative lines or the Cooperative can build new power lines according to the Line Extension Policy.

• Pedernales Electric Cooperative provides standard electric service from overhead lines. Underground electric service may be available at the sole option of the Cooperative. Service is provided at one rate, at one point of delivery, with one meter, at one of the Cooperative’s standard voltages. Non-standard service may be available if requested but only if the Cooperative determines such service is feasible, and the applicant agrees to pay any additional cost to the Cooperative for delivering such non-standard service.

• The applicant provides a meter loop conforming to the Cooperative’s standards and the National Electrical Code.

• The applicant’s installation and equipment must not be hazardous or of such type that satisfactory service cannot be given.

• Temporary service will be billed on the applicable rate. Before the Cooperative provides temporary service, the applicant must pay the estimated cost to the Cooperative of installing and removing these facilities.

200.2 Membership Fee

Membership in the Cooperative is required for service. Membership fees will be set by the Cooperative’s Board of Directors and shall be held until the last service connection for a member is terminated. Termination of membership does not release a member or member’s estate from debts owed the Cooperative.

200.3 Establishment Fee

A non-refundable $75.00 fee will be collected for connecting service and/or transferring account information. This fee is in addition to the membership fee and other fees required.

200.4 Same Day Service Fee

If service is available at a location and a request for same day connection is made after noon on Monday through Friday or on Saturdays or Sundays, a $250.00 non-refundable fee will be collected. This fee is in addition to the membership fee, establishment fee, and other fees required.

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200.5 Service to Rental Locations

Owners, operators, landlords or lessors who provide lease or rented units and require continued service during periods of vacancies shall be required to make application for electric service for each leased or rented unit and shall be subject to the conditions of service set forth in the Cooperative’s Membership Application and Certificate. Owners, operators, landlords or lessors shall be obligated to pay for such service but shall not be required to pay an establishment fee each time a vacancy occurs. Upon sale of property, the owners, operators, landlords or lessors are responsible for notifying the Cooperative to update the account status. Until a change is requested, the owners, operators, landlords or lessors is responsible for all bills.

200.6 Real Estate Show Fee

Temporary residential service will be provided for a non-refundable fee of $50.00 per day, four day maximum, to show residential property to potential buyers or renters. A membership fee will not be required. A Same Day Service Fee may also apply.

200.7 Continuity of Service

The Cooperative endeavors to provide continuous electric service but makes no guarantees against interruptions. If continuous service at a constant voltage is required, the member must install the necessary equipment. Should members require three-phase service, they shall be responsible for providing and operating such protective equipment as is necessary to protect their equipment from damage resulting from loss of power to one or more phases. If electric service is interrupted, the member must determine if the equipment and wiring is functioning properly. Cooperative personnel will not make repairs to members’ wiring or equipment The Cooperative shall not be liable for damages occasioned by interruption, failure to commence delivery, or voltage, wave form, or frequency fluctuation caused by interruption or failure of service or delay in commencing service due to accident to or breakdown of plant, lines, or equipment, strike, riot, act of God, order of any court or judge granted in any bona fide adverse legal proceedings or action or any order of any commission or tribunal having jurisdiction; or, without limitation by the preceding enumeration, any other act or things due to causes beyond its control, to the negligence of the Cooperative, its employee, or contractors, except to the extent that the damages are occasioned by the gross negligence or willful misconduct of the Cooperative.

200.8 Service Monitoring

This service is available for a fee of $7.50 per month. The Cooperative will monitor the member’s meter once a day and will notify the member or a designee if the power appears to be out on the member’s side of the meter. The Cooperative cannot guarantee the exact nature of the suspected outage, but can only detect and inform the member of a zero usage read on the member’s side of the meter.

200.9 Meter Tampering

A member’s account will be debited a $500.00 fee plus estimated energy consumed where meter tampering occurs.

200.10 Billing

Bills will be sent to members each month. Bills are due upon receipt and will become delinquent if not paid by the due date shown on the bill. Bills are not considered paid until Pedernales Electric Cooperative receives the payment. Accounts not paid by the due date may be assessed a $20.00 Late Payment Processing Fee. Bills to all non-residential accounts other than state agencies, may be assessed a Late Payment Processing Fee of $20.00 or 6% of the unpaid balance, whichever is greater, if not paid by the due date. All bills rendered to state agencies shall be in accordance with Chapter 2251 of the Texas Government Code. Bills will be calculated under the appropriate rate schedule. If the Cooperative finds that an account is being billed incorrectly, the account will be corrected immediately for future billings and the member will be notified.

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200.11 Underbilling

If the member’s account is under-billed because of failure to receive meter readings, faulty metering equipment, or other circumstance resulting in unreported use, the Cooperative will estimate the unbilled amount and adjust the member’s bill accordingly, up to 12 months

200.12 Payment

All bills for electric service are payable by mail, in person at any Cooperative office, or via any of the payment options offered by the Cooperative. The Cooperative may discontinue service to members who fail to pay for service within seven days from the date of the delinquent notice. Members may make arrangements with the Cooperative for payment of delinquent accounts so that they will not be disconnected for non-payment. If the Cooperative dispatches a service representative to collect a delinquent bill, a $75.00 Collection Fee will be included in the collection amount. Failure to pay a service representative the full amount owed at the time may result in immediate disconnection of service. If the member’s service is disconnected, a reconnection will not be made until the account is paid in full and a reconnection fee together with a deposit is paid. Under no circumstances will the Cooperative be liable for losses incurred resulting from the disconnection of service due to a member’s failure to pay for electrical service or any other reason for disconnection required by the Cooperative’s policies.

200.13 Payment Options

• Deferred Payment Arrangement - A deferred payment arrangement is an agreement between the Cooperative

and the Residential, Farm/Ranch, or Water Well member by which a delinquent account may be paid in installments that extend beyond the due date of the next bill. A member who is unable to pay his or her delinquent account and has not been delinquent on more than once in the last 12 months may be offered a deferred payment arrangement. The member must pay the current bill each month, plus the agreed upon portion of the amount deferred. Failure to fulfill the terms of the agreement will result in discontinuance of service and all amounts owed become due immediately. The Cooperative may decline to offer this plan if, in the Cooperative’s judgment, the member is lacking sufficient credit or satisfactory history to warrant further extension of credit or if the member has failed to provide complete, accurate and verifiable identification information when requested by the Cooperative.

• Fixed Payment Plan – This plan allows a member to pay a fixed amount per month based on twelve months

usage plus 10 percent divided by 12. A true-up and recalculation will be required no more than every 12 months. This plan is applicable to the Residential and Farm/Ranch and Water Well rates only. Members may enroll anytime with participation beginning with the first bill rendered after enrollment. Members who select this plan along with an automatic payment option will receive a discount on the first payment under the plan as follows: a) A 10% discount if member selects automatic bank draft, or b) A 5% discount if the member selects automatic credit card payment. The discount will only apply one time for the life of the account. The plan may be cancelled by either the member or the Cooperative upon notification to the other party. Upon cancellation the accumulated balance of the member’s account shall become due and payable. The Cooperative may decline to offer the Fixed Payment Plan if, in the Cooperative’s judgment, the member is lacking sufficient credit or satisfactory history to warrant payment plans or if the member has failed to provide complete, accurate and verifiable identification information when requested by the Cooperative.

• Average Payment Plan – Under this plan, the member’s monthly payment is the rolling 12 months average. This

plan is applicable to the Residential and Farm/Ranch and Water Well rates only. Members may enroll anytime with participation beginning with the first bill rendered after enrollment. Members who select this plan along with an automatic payment option will receive a discount on the first payment under the plan as follows: a) A 10% discount if member selects automatic bank draft, or b) A 5% discount if the member selects automatic credit card payment. The discount will only apply one time for the life of the account. The plan may be cancelled by either the member or the Cooperative upon notification to the other party. Upon cancellation the accumulated balance of the member’s account shall become due and payable. The Cooperative may decline to offer the Average Payment Plan if, in the Cooperative’s judgment, the member is lacking sufficient credit or satisfactory history to warrant payment plans or if the member has failed to provide complete, accurate and verifiable identification information when requested by the Cooperative.

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• Credit Card Payment Plan - The credit card payment plan allows residential members to pay their utility bills with an accepted credit card using one of the following options:

1. To pay automatically, a member can make arrangements by contacting a Cooperative representative and

requesting a payment plan be set up, or 2. To pay as needed, a member can contact a Cooperative representative and initiate the payment

transaction. The member will need to indicate the amount of the payment and provide necessary credit card information and authorization.

• Bank Draft Payment Plan - The bank draft payment plan allows members to authorize the Cooperative to draft

their checking accounts monthly. The amount drafted will be for: 1. The current bill due, or 2. The payment due as agreed on the Deferred Agreement.

The member’s checking account will be drafted automatically on the bill due date or on the due date of the Deferred Agreement contract.

200.14 Interconnection

Any interconnection with the Cooperative must be in accordance with the Cooperative’s Interconnection Policy for Small Generators and only after execution of the Cooperative’s Agreement for Interconnection.

200.15 Disconnection of Service

Service may be disconnected for any of the following reasons:

• The member in whose name the account is established may request disconnection. • The member’s account is delinquent and unpaid. • If the member pays a delinquent account balance with a check returned to the Cooperative for insufficient

funds. • Failure to comply with the terms of any payment agreement. • Failure to pay a deposit when required. • Where the Cooperative discovers that service is being obtained in any unlawful manner. • Where a known dangerous condition exists for as long as it exists. • If the member’s use of electric service interferes with the service of other members. • If required by the lawful ordinance of a municipality having authority to order such disconnection.

200.16 Reconnection Fee

The Cooperative will assess a $100.00 fee for reconnection after non-payment.

200.17 Disputed Bills

In the event of disputes between a member and the Cooperative regarding any bill for electric service, the Cooperative will investigate the circumstances and report the results to the member. If the dispute remains, the member may meet with a Cooperative representative to resolve it. If unresolved, the member will be advised of the Member Complaints procedures of the Cooperative. Members are obligated to pay billings that are not disputed.

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200.18 Member Complaints

The Cooperative has established procedures to address all complaints from members. Complaints will be investigated and the results will be reported to the complainant. If dissatisfied, the complainant may file a written complaint with either the Cooperative’s General Manager or Assistant General Manager. The complainant will be advised of the results within 10 days of the complaint. Service should not be disconnected before completion of the review. If the member chooses not to participate in a review, the Cooperative may disconnect service, provided proper notice has been issued under the disconnect procedures.

200.19 Returned Check/Denied Bank Draft/Denied Credit Card

The member’s account will be debited for the amount of each returned check, plus a $30.00 fee. If an account is setup for automatic payment by credit card or bank draft and then is denied, the member’s account will be debited for the denied amount, plus a $30.00 fee. If the member pays a delinquent account balance with a check returned to the Cooperative for insufficient funds the account will be disconnected.

200.20 Member Voting

Each member who is receiving service from the Cooperative shall be entitled to one (1) vote upon each matter submitted to a vote at a meeting of the members. At all meetings of the members at which a quorum is present, all questions shall be decided by a vote of a majority of the members voting thereon in person, by mail, or, when the option is made available to members, electronically, except as otherwise provided by law, the Articles of Incorporation of the Cooperative, or the Bylaws.

200.21 Member Access to Cooperative Records

A member, on written request, is entitled to examine and copy (at the member's expense), at any reasonable time, the books and records of the PEC. Requests for information are restricted to members of PEC, and the Cooperative reserves the right to charge a fee to the member, payable in part or wholly in advance, if fulfilling the request will require large amounts of employee time. Most of the information collected, assembled, or maintained in connection with the transaction of PEC business is available to members, with a few exceptions. Inspection of certain records may be limited or denied in cases including: privacy, attorney-client privilege; real estate subject matter, personnel subject matter, security; or matters that are clearly competitive, when the Board of Directors determines in good faith that disclosure presents a compelling risk of likely harm to the Cooperative or its members. This policy does not cover material that is requested as part of a legal proceeding. All member requests for information should be directed to: Open Records Request, Pedernales Electric Cooperative, Inc., P.O. Box 1, Johnson City, TX 78636.

200.22 Account Research Services

When records are requested by subpoena, a fee of $40.00 per hour will be charged to the requestor.

200.23 Easement Release

The Cooperative will assess a $300.00 fee for processing an Application for Easement Release.

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200.24 Switchover Policy

In cases where electric service is being provided to a member by the Cooperative and the member requests disconnection of electric service to obtain electric service from another utility certified to the area, the following rules shall apply: The member shall request the Cooperative, in writing, to disconnect electric service from the desired location. The member shall pay the following charges prior to disconnection:

• A charge of $100.00 to cover labor and transportation costs involved in the disconnection. • A charge for distribution facilities rendered idle as a result of the disconnection and not useable elsewhere

on the system based on the original cost of such facilities less accumulated depreciation, salvage, and any previous contribution in aid-to-construction.

• A charge for the labor and transportation costs involved in removing any idle facilities. This charge will only

apply if removal is requested by the disconnecting member, if removal is required for safety reasons, or if the salvage value of the facilities does not exceed such removal costs.

• All charges for electric service up to the date of disconnection.

Upon payment of the above charges, the member shall receive a paid receipt from the Cooperative for presentation to the connecting utility. The member shall be advised that the connecting electric utility may not provide service to said member until such connecting utility has evidence that the member has paid all charges provided for under this tariff.

200.25 Status of the Policy

The Service Policy is subject to change by the Board of Directors.

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300 Line Extension Policy

300.1 General Policy

The Cooperative extends its distribution facilities to members or applicants in accordance with the following line extension provisions. Each provision classifies the predominant type of electric service/use anticipated on member’s or applicant's premises and specifies conditions under which a line extension may be made. For each location where electric service is desired, member’s or applicant's classification involves an evaluation of the type of installation and its use. member’s or applicant's classification shall be determined by the Cooperative. In the event that the classification assigned by the Cooperative is incorrect based upon member’s or applicant's subsequent actual use of the installation then the Cooperative may alter member’s or applicant's classification and apply the correct line extension classification, making appropriate adjustment to the member’s or applicant's account or billing. Service will not be provided and no work to extend service to the applicant’s or member’s delivery point shall be performed until the applicant or member has paid any and all fees or charges associated with the provision of service. This includes membership fees, establishment fees, facilities charges, deposits, and/or system impact fees.

300.2 Permanent Overhead Residential, Farm, and Ranch Service

The Cooperative will construct a new overhead distribution extension consistent with the Cooperative’s current specifications to serve a permanent residential installation under the following provisions: A. Applicability.

To qualify as an extension to a permanent residential installation the location where member or applicant is requesting service shall comply with the following provisions: (1) be a permanent installation. To qualify as a permanent location, the applicant will either have a

definite plan for or has commenced the construction of the building or other permanent facilities stipulated in the application by installing a water well or slab/foundation.

(2) be a single or multi-family residence. (3) if located within a residential subdivision or multi-family residential development, the developer

must have complied with the residential development line extension policy of the Cooperative and paid all aid to construction required therein.

B. Point of Delivery.

The Cooperative extends its electric facilities only to the Point of Delivery (as defined in Section 100(4) of this Tariff). Member or applicant shall install and be solely responsible for wiring of the installation and all service entrance wiring through the weatherhead and the meter base to customer’s main disconnect switch or service center.

C. Facilities Charge. (1) The Cooperative shall estimate the cost for the line extension based on current unit material and

labor costs according to the Cooperative’s current standards and specifications. The estimated cost is the total cost of all construction including not only the labor and materials used in constructing the extension, but also engineering, right-of-way acquisition and clearing, and all other costs directly attributable to the extension.

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(2) There will be no charge to the member or applicant for the first $2000.00 of estimated cost of making the extension and such amount shall be the Cooperative’s obligation. The member or applicant shall be required to pay as aid to construction the estimated cost of the extension in excess of such amount.

D. Routing.

(1) The line extension shall be constructed along the most direct route. Any deviation from

the most direct route shall be at the Cooperative’s sole discretion.

(2) In all cases, the line extension shall be constructed on dedicated rights-of-way or on a route covered by an easement on the Cooperative’s standard form.

(3) Any and all right-of-way clearing shall be performed to the Cooperative’s specifications.

The estimated cost of the clearing shall be included in the estimated cost of the line extension. At the option of the member or applicant and with the agreement of the Cooperative, the applicant may perform the clearing or hire separately a contractor to perform the clearing, provided it is performed in a timely manner and to the Cooperative’s specifications.

E. System Impact Fee.

A non-refundable charge of $200.00 will be collected for extending service to a new point of delivery. This amount represents a contribution in aid of construction toward the Cooperative’s System Cost associated with substation and distribution backbone facilities and is in addition to any amount paid in excess of any amounts due for the line extension.

300.3 Other Residential, Farm, and Ranch Overhead Service Extensions

The Cooperative will construct a new extension of its overhead system to serve other residential installations

under the following provisions: A. Applicability.

To qualify as an extension to other residential class installations, the location where the member or applicant is requesting service shall:

(1) be a residence or dwelling unit not qualifying as a permanent installation; or (2) be a barn, shop, water well, gate opener, or other service that is not used for any commercial

purpose. B. Point of Delivery.

The Cooperative extends its electric facilities only to the Point of Delivery (as defined in Section 100(4) of this Tariff). Member or applicant shall install and be solely responsible for wiring of the installation and all service entrance wiring through the weatherhead and the meter base to member’s or applicant's main disconnect switch or service center.

C. Facilities Charge.

(1) The Cooperative shall estimate the cost for the line extension based on current unit material and labor costs for the same type of construction in the most recent data available. The estimated cost is the total cost of all construction including not only the labor and materials used in constructing the extension, but also engineering, right-of-way acquisition and clearing, and all other costs directly attributable to the extension.

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(2) There will be no charge to the member or applicant for the first $800.00 of estimated cost of making the extension and such amount shall be the Cooperative’s obligation. The member or applicant shall be required to pay as aid to construction the estimated cost of the extension in excess of such amount.

D. System Impact Fee.

A non-refundable charge of $200.00 will be collected for extending service to a new location. This amount represents a contribution in aid of construction toward the Cooperative’s System Cost associated with substation and distribution backbone facilities and is in addition to any amount paid in excess of any amounts due for the line extension

300.4 Other Overhead Line Extensions

The Cooperative will construct a new extension of its overhead distribution system to serve all other permanent

installations under the following provisions:

A. Applicability.

To qualify for an extension under this section 300.4, the location where member or applicant is requesting service shall:

(1) be a permanent installation, and (2) be classified as commercial, industrial, or public building installation; and (3) if located within a commercial development, the developer must have complied with the

commercial development line extension policy of the Cooperative and paid all aid to construction required therein.

B. Point of Delivery.

The Cooperative extends its electric facilities only to the Point of Delivery (as defined in Section 100(4)) of this Tariff). Member or applicant shall install and be solely responsible for wiring of the installation on member’s or applicant's side of the point of delivery.

C. Facilities Charge.

(1) The Cooperative shall estimate the cost for the line extension based on current unit material and

labor costs for the same type of construction. The estimated cost is the total cost of all construction including not only the labor and materials used in constructing the extension, but also engineering right-of-way acquisition and clearing, overhead, and all other costs attributable to the extension.

(2) A contribution in aid of construction for provision of electric service is required if the estimated

annual revenue from member or applicant, excluding purchased power cost, is less than the revenue requirement associated with the Cooperative’s system and direct investment costs of providing service to member or applicant. The amount of the customer’s contribution in aid of construction shall be determined by the following formula. If the amount calculated below is zero or negative, no contribution in aid of construction is required for provision of electric service.

Cooperative’s Allowable Investment (CAI) = Annual Revenue / Return Factor Total Project Cost (TPC) = Direct Cost + System Cost Member’s/Applicant's Contribution = TPC - CAI Where:

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Direct Cost = The cost of distribution or transmission facilities necessary to provide electric service to the member or applicant, determined by estimating all necessary expenditures, including, but not limited to overhead distribution facilities, metering and rearrangement of existing electrical facilities. This cost includes only the cost of the above-mentioned facilities that are necessary to provide service to the particular customer requesting service and does not include the costs of facilities necessary to meet future anticipated load growth, or to improve the service reliability in the general area for the benefit of existing and future customers.

System Cost = Cooperative’s average allocated investment costs and rate base items

associated with transmission backbone facilities, distribution substation facilities and distribution backbone facilities as determined from the Cooperative’s most recent cost of service study.

Annual Revenue = Annual revenue from the member or applicant computed using estimated billing units less the estimated annual cost of purchased power.

Return Factor = The fixed charge rate, including O&M, Depreciation, Taxes and a return on investment, necessary to convert an annual revenue stream to the total revenue associated with the life of the project.

(3) For members or applicants with loads greater than 1000 kW the Cooperative shall exercise

prudent judgment in determining the conditions under which a specific line extension will be made and shall view each case individually. The Cooperative shall analyze costs to provide service and base facilities charges on the rate of return generated by the rate design. Special contractual arrangements will be made with the member or applicant and may include contribution in aid of construction in advance of construction or as a monthly facilities charge, special contract minimums, special service specifications, special contract terms greater than 5 years, or other arrangements or conditions deemed reasonable by the Cooperative. All amounts paid to the Cooperative as contribution in aid of construction shall be non-refundable.

D. Contract Term.

Where a line extension is required to provide service, the Cooperative may require member or applicant to sign an Agreement For Electric Service or a term of up to 5 years, provided, however, that an agreement for a longer term may be required in accordance with Section 300.4(C)(3) above.

E. System Impact Fee.

A non-refundable charge of $200.00 will be collected for extending service to a new location. This amount represents a contribution in aid of construction toward the Cooperative’s System Cost associated with substation and distribution backbone facilities and is in addition to any amount paid in excess of any amounts due for the line extension.

300.5 Residential Developments

A. Applicability.

The Cooperative will construct a new extension of its overhead distribution system to provide service within residential developments under the following conditions:

(1) The development is a platted, recorded residential subdivision to be primarily used or developed

for permanent single or multi-family residential dwelling units; (2) The land developer shall comply with all applicable provisions of the Service Rules and

Regulations of the Cooperative;

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(3) All Cooperative facilities will be installed in recorded public or private easements along streets or

public rights-of-way deemed suitable by the Cooperative; (4) Cooperative facilities will not be installed along the backs of lots or in areas deemed inaccessible

by the Cooperative; (5) The developer provides at no cost to the Cooperative:

(a) Right-of-way easements and covenants on owner’s property that are satisfactory to the Cooperative;

(b) Site plans (streets, wet utilities, mechanical, electrical, plumbing, and landscaping plans,

etc.), notice of construction start dates and construction schedules that are reasonable and industry typical for the type of work to be performed.

(c) Survey points for grades, lot corners, street ROW, and other locations reasonably necessary

for installation of the electric system.

B. Facilities Charge.

(1) The Cooperative shall estimate the cost for the electric facilities adequate to serve all prospective members in the development. These facilities will include primary, secondary, electric equipment, and devices required for service to the development, based on current unit material and labor costs for the same type of construction in the most recent data available. The estimated cost is the total cost of all construction including not only the labor and materials used in constructing the extension, but also engineering, right-of-way acquisition and clearing, and all other costs directly attributable to the extension.

(2) The developer will bear the cost of the facilities, identified in paragraph B.1 of this section,

required for the distribution system within the subdivision. Each member or applicant for residential service within the subdivision shall receive service under the provisions of section 300.2 of this policy and shall be responsible for any contributions in aid of construction and any system impact fees required by the provision of such service.

Any commercial facilities associated with the development such as offices, clubhouses, laundry facilities, etc. shall be separately considered under the provisions of section 300.4. The developer or member or applicant for such service shall be responsible for any contributions in aid of construction and any system impact fees required by the provision of such service.

(3) Any undue cost experienced by the Cooperative during the construction of the distribution system

within the subdivision to placement of obstacles by the developer or home builder will be paid by the developer, home builder, member or applicant.

(4) All amounts paid to the Cooperative for construction shall be non-refundable. (5) All Cooperative facilities required within the limits of the subdivision will be installed prior to the

provision of service to individual applicants.

300.6 Commercial Developments

A. Applicability.

The Cooperative will construct a new extension of its overhead distribution system to provide service within commercial developments where developer requests electric infrastructure to be installed in advance of development of a site or lot by a member or applicant, under the following conditions:

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(1) The development is a platted commercial development with sites or lots for multiple members or applicants to be primarily used or developed for permanent commercial, industrial, retail, and/or office use;

(2) The land developer shall comply with all applicable provisions of the Service Rules and

Regulations of the Cooperative; (3) The developer will provide at no cost to the Cooperative:

(a) Right-of-way easements and covenants on owner’s property that are satisfactory to the Cooperative;

(b) Site plans (streets, wet utilities, mechanical, electrical, plumbing, and landscaping plans,

etc.), notice of construction start dates and construction schedules that are reasonable and industry typical for the type of work to be performed.

(c) Survey points for grades, lot corners, street ROW, and other locations reasonably necessary

for installation of the electric system. (4) Line extensions to each member or applicant within the development will be according the terms and

conditions in section 300.4 – Other Line Extensions.

B. Facilities Charge.

(1) The Cooperative shall estimate the cost of the electric infrastructure adequate to serve all prospective members within the development. This will be determined in advance of development of a site or lot by a member or applicant based on current unit material and labor costs for the same type of construction. The estimated cost is the total cost of all construction including not only the labor and materials used in constructing the extension, but also engineering right-of-way acquisition and clearing, overhead, and all other costs attributable to the extension.

(2) The developer will be required to pay in advance 100% of the estimated actual cost of such

electric infrastructure. The Cooperative at its sole discretion may accept other guarantee or contractual arrangement in lieu of cash payment.

300.7 Underground Service

A. The following provisions for the extension of underground service to individual members/applicants or

residential or commercial developments are in addition to the standard provisions relating to overhead service.

B. Underground Service to Individual Members or Applicants:

Underground electric primary and secondary lines to serve members or applicants may, by special arrangement with the Cooperative, be provided subject to the condition that the member or applicant shall bear the cost of installing the lines underground and the Cooperative shall provide a pad-mount transformer and the termination for the underground lines at the transformer.

C. Underground Service to Subdivisions or Commercial Developments:

Where a subdivider requests the construction of underground electric facilities within a platted subdivision, the developer shall bear the cost of installing the underground electric system adequate to serve all prospective members who may require electric service from said underground system and the Cooperative shall provide the necessary pad-mount transformers and the terminations for the underground lines at the transformers.

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D. Where the design of the development is such that switchgear are required for proper and safe operation of the distribution system, the developer will bear the cost of the switchgear. Where switchgear are installed solely for the convenience of the Cooperative, such as to provide flexibility in serving load outside of the development, then the Cooperative shall bear the cost of such switchgear.

E. In all cases, underground secondary service lines from a meter to the member’s main disconnect switch

or service center shall be installed and maintained by the member and the Cooperative shall have no responsibility or liability in connection therewith.

300.8 Temporary Service

In any circumstance where the need for electric service is temporary the member or applicant shall pay 100 % of the estimated cost of construction plus the cost of removal.

300.9 Area Lighting

The Cooperative will provide secondary service conductor to serve an area lighting fixture without charge to the member or applicant. Member or applicant will pay in advance as non-refundable aid to construction the estimated cost of any additional facilities.

300.10 Line Clearance

The Cooperative will assist in the transportation of oversized objects through the area or in the construction of buried pipelines or other objects with the Cooperative’s right-of-way by temporarily de-energizing Cooperative facilities or temporarily relocating or raising electric facilities provided that the Cooperative receives compensation for all costs incurred. Costs incurred shall include labor, materials used, engineering, right of way acquisition and clearing, and vehicles or equipment used including mileage if applicable.

300.11 Ownership of Distribution Facilities

The Cooperative shall retain the ownership of all material and facilities installed by the Cooperative, developer, or applicant for the distribution of electric energy whether or not the same have been paid for by the member. All lines and facilities constructed or installed by the Cooperative are the property of the Cooperative

300.12 No Refund of Aid to Construction

Payments necessary for construction of facilities which will be used to deliver electric energy to the applicant or member are contributions in aid of construction and are not refundable.

300.13 Relocation of Facilities

A. The Cooperative will relocate its facilities on member’s or applicant's premises at member’s or applicant's

request provided member or applicant has (1) provided a satisfactory easement for the new facilities; and (2) paid in advance the estimated cost of the removal of the old facilities plus the estimated cost for the construction of the new facilities.

B. If the Cooperative determines it is necessary to move its facilities because member or applicant fails or

refuses to allow the Cooperative access to Cooperative’s facilities at any time then member or applicant may be billed the estimated cost of relocation.

C. The Cooperative will replace an existing overhead electric line with an underground line upon request of a

member or applicant, land owner, or other party, provided, however, that Cooperative has

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(1) determined in its sole discretion that such replacement does not adversely impact electric service reliability or the Cooperative’s operating efficiencies,

(2) received an adequate easement(s), in a form acceptable to the Cooperative, for the construction,

installation, maintenance, operation, replacement and/or repair of the underground facilities, at no cost to the Cooperative, and

(3) received payment in advance of the commencement of such replacement for all costs of removal

of the overhead facilities and the full amount of the Cooperative’s estimated cost for the construction and installation of the new underground facilities.

300.14 Formula for Calculating Contribution in Aid of Construction

The amount of the contribution in aid of construction for electric service is determined by the following formula. If amount calculated below is zero or negative, no contribution in aid of construction is required for provision of electric service. Cooperative's Allowable Investment = Annual Revenue / Return Factor Total Project Cost = Direct Cost + System Cost Member/Applicant Contribution = Total Project Cost - Cooperative's Allowable Investment Where: Direct Cost = The cost of distribution or transmission facilities necessary to provide electric service to

member or applicant, determined by estimating all necessary expenditures, including, but not limited to, metering, services, transformers, and rearrangement of existing electrical facilities. This cost includes only the cost of the above-mentioned facilities that are necessary to provide service to the particular customer requesting service and does not include the costs of facilities necessary to meet future anticipated load growth, or to improve the service reliability in the general area for the benefit of existing and future customers.

System Cost = Cooperative's average allocated investment costs associated with member's or applicant's

on-peak and off-peak demands as approved in Cooperative's most recent rate case for the appropriate class of member or applicant. Investment cost accounts considered in determining the allocated investment costs are those applicable 300 series FERC accounts and other rate base items, including plant held for future use, cash working capital, materials and supplies, prepayments, customer deposits, reserve for insurance and other cost-fee capital.

Annual Revenue = Estimated annual revenue from member or applicant computed from estimated demand

and kWh, excluding fuel cost and sales tax. Return Factor = Fixed charge rate, including O&M, taxes, insurance, necessary to convert an annual

revenue stream to the total revenue associated with estimated life of project.

400 CREDIT REQUIREMENTS AND DEPOSITS

400.1 Credit requirements for permanent residential applicants and members.

(A) The Cooperative will require an applicant for residential service or an existing residential member to

establish and maintain satisfactory credit as a condition of providing service.

(1) Establishment of credit shall not relieve any member from complying with the Cooperative's requirements for prompt payment of bills.

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(2) The credit worthiness of spouses established during shared service in the 12 months prior to their divorce will be equally applied to both spouses for 12 months immediately after their divorce.

(B) An applicant for residential service or an existing residential member can establish satisfactory credit by:

(1) clearing any unpaid or delinquent balances prior to re-establishing service with the Cooperative; and

(2) meeting and adhering to the Cooperative’s payment policies and/or payment plan such that:

(i) during the most recent 12 consecutive months of service the member is not late in paying a bill more than once;

(ii) the member does not have service disconnected for nonpayment; and (iii) the member does not have more than one returned check.

(3) As an applicant, having been a customer of any electric service provider for the same kind of

service within the last two years and not having been delinquent more than once in payment of any such electric service account in the most recent 12 consecutive months of service and evidenced by a letter of credit history from the applicant's previous electric service provider.

(4) As an applicant, having a credit risk assessment conducted by the Cooperative or on its behalf

and receiving a satisfactory credit risk assessment.

(C) If satisfactory credit cannot be established by the residential member using these criteria, the member may be required to pay a deposit pursuant to this section.

400.2 Credit requirements for non-residential members or applicants.

For non-residential service, if an applicant's or existing member’s credit has not been demonstrated satisfactorily to the Cooperative, the applicant or member may be required to pay a deposit in an amount not to exceed one-sixth of the annual estimated bill. Satisfactory credit may be demonstrated by (a) an applicant or member for a period of 24 consecutive non-residential billings without having service disconnected for nonpayment of a bill and without having been delinquent in the payment of bills more than once or (b) as an applicant, having been a customer of any electric service provider for the same kind of service within the last two years and not having been delinquent more than once in payment of any such electric utility service account in the most recent 24 consecutive months of service and evidenced either by a satisfactory letter of credit history from the applicant's previous electric service provider or by a satisfactory credit risk assessment conducted by the Cooperative or on its behalf.

400.3 Deposits.

(A) (1) An applicant, who has not previously received service from the Cooperative, will be required to pay a

fixed deposit in the amount of $150 for residential service or $300 for non-residential service (i) in the event the applicant fails to provide complete, accurate and verifiable identification information when requested by the Cooperative when applying for electric service or (ii) in the event the applicant fails to either (a) provide a satisfactory letter of credit history from its previous electric service provider or (b) receive a satisfactory credit risk assessment conducted by the Cooperative or on its behalf.

(2) An existing member when applying for additional electric service, will be required to pay a fixed

deposit in the amount of $150 for residential service or $300 for non-residential service (a) in the event the existing member fails to provide complete, accurate and verifiable identification information when requested by the Cooperative or (b) in the event the member failed to satisfactorily demonstrate to the Cooperative the member's creditworthiness or otherwise demonstrated a previous history of neglect to fulfill membership obligations, such as (but not limited to) paying a bill late more than once during the most recent 12 consecutive months of service, service disconnection for nonpayment, failure to meet obligations under a deferred payment agreement, return of a check for insufficient funds, theft of service, meter tampering, safety code violations or fraud. If the member applying for

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additional electric service has less than 12 consecutive months of service, that member may provide a satisfactory letter of credit history from its previous electric service provider or have a credit risk assessment conducted by the Cooperative or on its behalf and receive a satisfactory credit risk assessment.

(B) An applicant, who previously had service with the Cooperative, or an existing member, each of whom

failed to satisfactorily demonstrate to the Cooperative creditworthiness or otherwise demonstrated a previous history of neglect to fulfill membership obligations may be required to pay a deposit (a) in an amount of $150 for residential service or $300 for non-residential service or (b) in an amount not to exceed one-sixth of the annual estimated bill in the event the applicant or member fails to provide complete, accurate and verifiable identification information when requested by the Cooperative.

(C) If the applicant or existing member already has paid a fixed deposit, the applicant or member may be

required to pay an additional deposit up to a total deposit amount not to exceed one-sixth of the annual estimated bill.

(D) The Cooperative may refuse to provide service to an applicant or member if the requested deposit is not

paid at the initiation of service. The Cooperative may also refuse to reconnect service to an applicant or existing member if the requested deposit is not paid upon request.

400.4 Deposits for temporary or seasonal service and for weekend residences.

The Cooperative will require a deposit sufficient to reasonably protect it against the assumed risk for temporary or seasonal service or weekend residences, as long as the policy is applied in a uniform and nondiscriminatory manner. These deposits shall be returned according to guidelines set out in subsection 400.8.

400.5 Amount of deposit.

The total of all deposits from a member or applicant for service shall not exceed one-sixth of the estimated annual billing; provided however, that for those members or applicants subject to the fixed deposit amount described in Section 400.3 above, the amount of the deposit shall not be less than the amount of those fixed deposits.

400.6 Interest on deposits.

The Cooperative shall pay interest on any required deposits at an annual rate at least equal to that set by the Public Utility Commission of Texas on December 1 of the preceding year, pursuant to Texas Utilities Code §183.003 (Vernon 1998) (relating to Rate of Interest). If a deposit is refunded within 30 days of the date of deposit, no interest payment is required. If the Cooperative keeps the deposit more than 30 days, payment of interest shall be made retroactive to the date of deposit. (A) Payment of the interest to the member shall be made annually or at the time the deposit is returned or

credited to the member's account. (B) The deposit shall cease to draw interest on the date it is returned or credited to the member's account.

400.7 Records of deposits.

(A) The Cooperative shall keep records to show:

(1) the name and address of each depositor; (2) the amount and date of the deposit; and (3) each transaction concerning the deposit.

(B) The Cooperative shall issue a receipt of deposit to each applicant or member paying a deposit and shall

provide means for a depositor to establish a claim if the receipt is lost. (C) The Cooperative shall maintain a record of each unclaimed deposit for at least four years.

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(D) The Cooperative shall make a reasonable effort to return unclaimed deposits.

400.8 Refunding deposits.

(A) If service is not connected, or is disconnected, the Cooperative shall promptly refund the member's or

applicant’s deposit plus accrued interest on the balance, if any, in excess of the unpaid bills for service furnished.

(B) When the member has paid bills for service for 12 consecutive residential billings or for 24 consecutive

non-residential billings without having service disconnected for nonpayment of a bill and without having been delinquent in the payment of bills more than once, or has not had more than one returned check, the Cooperative shall promptly refund the deposit plus accrued interest to the member or credit the amount of the deposit and accrued interest to the member’s account. The deposit may be retained if the member (1) does not meet the foregoing refund criteria or (2) failed to provide complete, accurate and verifiable identification information when requested by the Cooperative.

400.9 Re-establishment of credit.

A member whose service has been disconnected for nonpayment of bills or theft of service (meter tampering or bypassing of meter) shall be required, before service is reconnected, to pay all amounts due the Cooperative, including reconnection and other applicable fees, and reestablish credit.

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500 FEE SCHEDULE

FEE SCHEDULE

DESCRIPTION

FEES

Membership Fee $ 50.00

Establishment Fee $ 75.00

Deposits Refer to Section 400 Credit Requirements and Deposits

System Impact Fee $ 200.00

Facilities charge Refer to Section 300 Line Extension Policy

Same day service at existing location $ 250.00

Real Estate Show Fee $ 50.00 per day, 4 day maximum

Service Monitoring Fee $ 7.50 per month

Meter Tampering $ 500.00

Late Payment Processing Fee

$ 20.00 for residential; $20.00 or 6% of unpaid balance whichever is greater for non-residential accounts other than state agencies

Collection Fee $ 75.00

Reconnection Fee (reconnection after non-payment) $ 100.00

Return Check/Denied Bank Draft/Denied Credit Card $ 30.00

Open Records Fee – Staff research time $ 40.00 per hour

Open Records Fee – Copies $ .25 cents per page for any pages in excess of 10 pages

Open Records Fee – Other materials and services not included in research time and copies.

Actual cost

Account Research Services by Subpoena $ 40.00 per hour

Easement Release $ 300.00

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Sponsors:



Subject: Member Assistance Program Policy Revision

Submitted By: Eddie Dauterive

Department: Member Services


• Amended MAP Policy Resolution 2 120210 (PDF)

20.B.2

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December 20, 2010

RESOLUTION 2010-121

Member Assistance Program Policy Revision

NOW, THEREFORE, BE IT RESOLVED BY THE BOARD OF DIRECTORS OF THE COOPERATIVE, that the Cooperative amends and restates the Member Assistance Policy as attached, with any amendments approved by the Board this day, to be effective as of January 1, 2011; and

BE IT FURTHER RESOLVED, that any policy concerning the Member Assistance Program approved previous to this day is hereby superseded, including but not limited to the policy passed by Board resolution on April 20, 2009; and





AYES: Clement, Scanlon, Fischer, Landaker, Cox

NAYS: Chris Perry

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-1-

MEMBER ASSISTANCE POLICY PEDERNALES ELECTRIC COOPERATIVE, INC.

BOARD ADOPTED: December 20, 2010 RESOLVED BY THE BOARD OF DIRECTORS OF THE COOPERATIVE That to provide financial assistance to members of the Cooperative, the Cooperative will allocate an amount annually to the Member Assistance Program (MAP) with the following guidelines:

Participating Community Action, other qualified organizations and county agencies will qualify members seeking assistance consistent with Comprehensive Energy Assistance Program requirements.

PEC funds will be available to members whose income is less than 250% of the

published Federal Poverty Level.

Each qualifying member will be limited to a maximum of $500 per calendar year.

PEC will provide each agency with a report that includes details on each transaction, identifies apparent exceptions to standard rules; the percentage of the total allocation distributed each month, and the balance amount of funds remaining for each agency.

The agency will fax or email to PEC their distribution notification on the PEC

pledge form, which confirms that the member has met the specified qualifications, attested to with an agency representative’s signature on the appropriate line.

The PEC Member Assistance Program Administrator will contact each agency at

least once a month to facilitate communication between the agencies and the Cooperative to optimize the benefit to our members in providing financial assistance. The Administrator will also communicate with staff administering the program to review the effectiveness of the program and to resolve any issues.

PEC reserves the right to deny participation in the program to any member

perpetrating or attempting to perpetrate fraud against the Cooperative, for example: meter tampering, providing false identification information, etc.

Agencies have the right to deny participation in the program to any member who

perpetrated fraud against their agency or is not willing to participate in programs required to support self-sufficiency.

MAP distributions are limited to members only. Therefore, funds can only be

used for the person whose name is on the account or their spouse.

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-2-

MAP distributions are not permitted to be used for prior accounts already in the collections process (otherwise know as “write-off” accounts).

MAP distributions may be used towards establishment fees, but not towards

membership fees or deposits.

MAP funds will be allocated to the agencies annually with the caveat that PEC will assess agency use of funds on a quarterly basis, with the possibility of redistributing these limited funds to the best advantage of our members.

PEC reserves the right to refer MAP recipients for an energy audit, if appropriate.

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Sponsors:



Subject: Capital Credits Policy

Submitted By: Aisha N Hagen



• PEC Capital credits policy for 2010-12-20 Package AH2(PDF)

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December 20, 2010

RESOLUTION 2010-122

Capital Credits Policy

NOW, THEREFORE, BE IT RESOLVED BY THE BOARD OF DIRECTORS OF THE COOPERATIVE, that the Cooperative adopts the Capital Credits Policy as attached, with any amendments approved by the Board this day, to be effective as of January 1, 2011 with an implementation date of April 1, 2011; and

BE IT FURTHER RESOLVED, that any policy concerning distribution of capital credits approved previous to this day is hereby rescinded as of December 31, 2010, including but not limited to each policy passed by Board resolution on November 9, 2007 concerning capital credits and member equity targets; and






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Page 1 of 3

CAPITAL CREDITS POLICY

Amended and Restated: December 20, 2010 Effective Date: January 1, 2011

Implementation Date: April 1, 2011

I. Objective

The objective of this Capital Credits Policy (“Policy”) is to state the general policy of Pedernales Electric Cooperative, Inc. (“Cooperative”) for allocating and retiring capital credits.

II. Policy The Cooperative will allocate and retire capital credits in a manner that permits the Cooperative to comply with all applicable laws, all restrictions imposed by its debt financing covenants, the Cooperative Articles of Incorporation and Bylaws, is fair to the Cooperative’s members and former members, and is reasonable to maintain a healthy financial state.

III. Expectations A. Board approval. The Cooperative will allocate and retire capital credits in the manner described in this policy and approved by the Board. B. Net margin allocations. Each member purchasing electricity from the Cooperative will receive an allocation of the net margins (profits) made by the Cooperative during the year based upon the amount purchased by the member during the year unless the member has a negative total of purchases during the year. C. Net loss allocations. If the Cooperative has a loss in a given year, that loss will not be allocated to members. Instead, that loss will be rolled forward and combined with the positive net margins in the succeeding year(s) and the remaining net margins will then be allocated to the members. D. General capital credit retirements. General retirements will be correlated to the assumptions and limitations contained in an Equity Management Plan to be approved annually. This correlation serves as the basis for a Board affirmative determination of adverse impact to the Cooperative. The Board shall make this affirmative determination prior to any retirement. All retirements must comply with restrictions placed on PEC by its lenders, its Articles of Incorporation, Bylaws and state and federal law. Each year, the Cooperative will retire capital credits in the following order:

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Page 2 of 3

1.) Retire total allocation of capital credits to the estates of deceased members. (see description below for Unscheduled Retirements) 2.) Retire approximately one-half of the remaining capital credits from the oldest outstanding year(s) that have not yet been retired. 3.) Retire the remaining capital credits from the most recent year(s) that have been allocated. E. Capital credit retirements - Unscheduled. The Cooperative may retire capital credits, outside the normal schedule for retirements, when the cooperative receives proper notification that a member or former member has died. The Cooperative will pay the discounted, net present value of the capital credits to the estate of the deceased member. The amount of this distribution will be calculated using a discount rate that equals the Cooperative’s weighted cost of capital and taking into account the date that the distribution would have occurred in the normal schedule of retirements. F. Recoupment. If a member or former member has a balance due to the Cooperative, the Cooperative may choose to apply part or all of the capital credits being retired to the member’s (or former member’s) account.

IV. Limitations A. Forfeiture of capital credits. The Cooperative shall not enter any agreements through which a member or former member forfeits the right to the allocation or retirement of capital credits. B. Member classes. If the Board approves, the Cooperative may allocate or retire capital credits to similar classes of members or former members under different manners, methods, timing, and amounts, as long as the Cooperative allocates and retires capital credits to similar classes, members and former members using the same manner, method, timing, and amount. C. Notice of Allocation. The Cooperative shall notify each member in writing of the amount allocated to the member for the preceding fiscal year within eight and one-half months following the end of the fiscal year. D. Method of payment. The Cooperative will retire capital credits to members either in cash or by bill credits, whichever the Board of Directors determines will be most effective and in the Cooperative’s best interest. E. Records. The Cooperative will keep complete records of the amount of capital credits that have been allocated to each member, along with a record of the retirements to that member. This information will be available upon request to each member. F. Unclaimed capital credits. If a member/former member fails to cash or claim a capital credit retirement check, then the Cooperative shall send a notice to the member’s or former member’s most current address listed on the Cooperative’s

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Page 3 of 3

records calling this failure to the member’s attention. If the check remains unclaimed after three years, the distribution may be delivered in accordance with Section 74.3013 of the Property Code to a scholarship fund, to an economic development fund and to an energy efficiency assistance fund, each as further described and to the limits described in such Section 74.3013 of the Property Code. Otherwise, such amounts will be reported and remitted to the State Comptroller’s Office in accordance with current State of Texas unclaimed property laws.

V. Responsibility A. Implementation of Policy. The Cooperative’s General Manager is responsible for implementing this policy and for developing the practices and procedures necessary to allocate and retire capital credits according to this policy. B. Recommendations to the Board. The Cooperative’s General Manager is responsible for: (1) recommending to the Board the manner, method, timing, and amount for allocating and retiring capital credits; and (2) when changes are felt to be in the best interest of the Cooperative and its members and former members, recommending revisions to this policy to the Board. C. Education and Communication. The Cooperative’s General Manager is responsible for developing and implementing a program to (1) educate employees and members about the role of Capital Credits in the cooperative business model and (2) effectively inform employees and members about annual allocations and retirements. D. Review and Approval by Board. The Board is responsible for: (1) reviewing, discussing, and evaluating the Manager’s recommendations regarding the allocation and retirement of capital credits; (2) approving or proposing changes to these recommendations; (3) reviewing, discussing, and evaluating this policy every year; (4) reviewing, discussing, and evaluating the Manager’s recommendations for revising this policy; (5) revising this policy. E. Compliance with Policy. The Board is responsible for the Cooperative’s compliance with this policy.

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Sponsors:



Subject: Bylaws Revision for Capital Credits Discounting

Submitted By: Aisha N Hagen


Background:

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December 20, 2010

RESOLUTION 2010-123

Bylaws Revision for Capital Credits Discounting

RESOLVED BY THE BOARD OF DIRECTORS OF THE COOPERATIVE, that Article VII Section 2 of the Cooperative Bylaws is amended as follows (insertions underlined) by adding the following provision as the last paragraph of that section:

As determined by the Board, before the time the Cooperative anticipates normally retiring and paying Patronage Capital, the Cooperative may retire some or all Patronage Capital and pay the net present value of the retired Patronage Capital. If the Cooperative retires and pays the net present value of Patronage Capital to a Member or former Member before the time the Cooperative anticipates normally retiring and paying the Patronage Capital, then the amount of Patronage Capital not paid may be retained as permanent equity.






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Sponsors:


Updated: 1/14/2011 2:20 PM by Sylvia A. Romero A Page 1

Subject: Use of Title Chief Executive Officer



Background:

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December 20, 2010

RESOLUTION 2010-124

Change of Title from General Manager to Chief Executive Officer

NOW, THEREFORE, BE IT RESOLVED BY THE BOARD OF DIRECTORS OF THE COOPERATIVE, that the terms “General Manager” and “Acting General Manager” in any document, policy, procedure, or instrument generated or maintained by the Cooperative shall refer to, respectively, “Chief Executive Officer” and “Acting Chief Executive Officer;” and

BE IT FURTHER RESOLVED that any provision applicable to the General Manager or Acting General Manager shall be applicable to, respectively, the Chief Executive Officer or Acting Chief Executive Officer; and

BE IT FURTHER RESOLVED that nothing in this resolution shall affect the applicability of policies concerning the General Manager to the Acting General Manager, or the applicability of policies concerning the Chief Executive Officer to the Acting Chief Executive Officer; and

BE IT FURTHER RESOLVED that, consistent with the Cooperative Bylaws, anypolicy or document promulgated by the Board after this date shall employ the language “Chief Executive Officer” or “Acting Chief Executive Officer,” rather than “General Manager” or “Acting General Manager;” and

BE IT FURTHER RESOLVED that effective Nov. 15, 2010 Acting General Manager Luis A. Garcia, is designated “Acting Chief Executive Officer,” until the Board otherwise acts to change that title and all actions taken prior to the effective date hereof by the officers and duly authorized agents of the Cooperative, including, the execution and delivery of any relevant document with such designation are hereby confirmed, ratified and approved.





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Updated: 1/12/2011 9:05 AM by Renee Oelschleger Page 1

Subject: Amendment to Delegation of Authority/Gen. Counsel



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December 20, 2010


Amendment to Delegation of Authority Regarding General Counsel

RESOLVED BY THE BOARD OF DIRECTORS OF THE COOPERATIVE, that the PEC Board Policy on Authority and Responsibilities (the "Delegation of Authority Policy"), initially adopted on September 15, 2008, and amended on November 17, 2008, November 16, 2009, March 15, 2010 and September 20, 2010 be further amended by making the following changes to items "b)" and "c)" in the section entitled "Authority Reserved to the Board of Directors", as follows (insertions underlined, deletions strike through):

b)Confirm the General Manager's appointment of Approve the appointment and employment terms, and periodically review the performance of the PEC General Counsel.

c)Consult with the General Counsel, independent of the General Manager. in a manner that recognizes that the General Counsel’s legal client is the Cooperative, as an entity. This reservation is not exclusive, and does not withhold from the General Manager the authority to separately consult with the General Counsel.

to read:

b) Approve the appointment and employment terms, and periodically review the performance of the PEC General Counsel.

c) Consult with the General Counsel in a manner that recognizes that the General Counsel’s legal client is the Cooperative, as an entity.

and;

BE IT FURTHER RESOLVED BY THE BOARD OF DIRECTORS OF THE COOPERATIVE, that in the section entitled "Delegation of Authority to the General Manager," the existing item "d)" is stricken and the subsequent item "e)" is relabeled as item "d)," as follows:

d) Appoint the PEC General Counsel, subject to Board Approval.

e) Consult with the General Counsel.

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and;

BE IT FURTHER RESOLVED, that the Acting General Manager Chief Executive Officeror his designee is authorized to take such actions as needed to implement this resolution.



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PEC: 2010 Year in ReviewPEC: 2010 Year in Review

2010 Year in Review2010 Year in Review

• Adopted completely overhauled, updated Bylaws

• Member Bill of Rights overwhelmingly approved

• PEC’s Board is now completely comprised of democratically elected directors with the election of Ross Fischer and Chris Perry

• Paying back over $14 million in capital credits, satisfying settlement agreement

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• Compensation study completed and presented to Board

• Received clean 2009 audit from BKD

• Consolidated equity ratio improved to 27% (as of October), up from 24% in Dec. ’09; this ratio was 17% after our accounting recalibration

• Approved first formal budget and long-term capital improvement plan; projected $5.1 under 2010 budget (controllable expenses)

• Utilized internal auditors to assess operational effectiveness


• Launched new website with Power of Community theme

– Paperless billing

– Connect/disconnect service

– Interactive conservation tools

– Kids Zone

– Video communications

– Service requests

• PEC Quarterly launched — member newsletter included with bills providing insight into PEC business

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• PCA adjustments in June and August reduced power costs for members

• Initiated Smart Grid pilot program

• Worked with power supplier to obtain additional wind-generated power, supporting Board’s renewable energy goal


• Achieved key performance indicators

• Restructured LINKS ERP project, currently configuring the SAP system to fit PEC’s needs

• Made Whistleblower information more visible for employees;Legal Dept. is sole contact for Whistleblower functions

• Recognized by Texas Mutual Insurance Company for the efficiency and cost-effectiveness of PEC’s workers’compensation claims program

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Special Meeting www.pec.coop

~ Minutes ~ Call PEC Toll Free

1-888- 554-4732

Tuesday, January 4, 2011 10:00 AM PEC Headquarters Auditorium


1. Call to Order

10:00 AM Meeting called to order on January 4, 2011 at PEC Headquarters Auditorium, 201 South Avenue F, Johnson City, TX.

Attendee Name Title Status ArrivedCristi Clement District 1 Director/Secretary-Treasurer Present 10:00 AMKathryn Scanlon District 3 Director Present 10:00 AMChris Perry District 4 Director/Vice President Present 10:00 AMRoss Fischer District 5 Director Present 10:00 AMLarry Landaker District 6 Director/President Present 10:00 AMDr. Patrick Cox District 7 Director Present 10:00 AM

2. Open Session


During the morning session of the Special Board meeting, the following members spoke on topics including but not limited to the following:

a. Ken Rigsbee - reported on group of cooperative members forming an owners council to communicate with each other and organize in case legal action needs to be taken, and requested cautious spending.

b. Milton Hawkins - review time limitations for members addressing the Board, examine ending monthly payments to Bennie Fuelberg, and requested information on executive search selection process.

c. Merle Moden - read passages from Navigant report regarding former General Manager, provided recommendations for future CEOs, and suggested a minimum of five minute time limitations for members addressing Board.

b. Ernest Altgelt - distributed excerpt from court transcript dated December 7, 2010, requested amount of direct losses, agreed with forfeiture as stated by Mr. Hawkins, and outlined proposal to Judge Mills regarding charity benefiting Hill Country.

President Larry Landaker announced that this Special Called Meeting was held to discuss our executive search for the Chief Executive Officer. At 10:20am, President Landaker stated that the Board was going into Executive Session and would reconvene later this afternoon.


A. Personnel Matters:

3.B

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Special Meeting Minutes January 4, 2011


1. Discussion Regarding Executive Search

5. Reconvene to Open Session

6. Items from Executive Session

President Larry Landaker made the following statement:The Board met in Executive Session to consider candidates for the position of Chief Executive Officer. A short list has been identified and finalists will be interviewed privately by the Board over a two day period, January 17 & 18 at a location to be announced. On those days it will be necessary to hold a Special Called Meeting of the Board. The Board will narrow the number of finalists on those days and the Board will ask those candidates to return for a lengthy interview at the end of January or the first part of February when another called meeting will occur and a final decision may be made. At no time during the process will the confidentiality of any candidate be breached by the Board.

7. Adjourn

There being no further business to come before the Board of Directors, meeting was adjourned.

____________________________________ Cristi Clement, Secretary APPROVED:

_______________________________________ Larry Landaker, President

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CONFLICT OF INTEREST POLICY PEDERNALES ELECTRIC COOPERATIVE, INC.

BOARD ADOPTED: December 16, 2008

Conflict of Interest Certification and Disclosure Form As defined in the Pedernales Electric Cooperative, Inc. Conflict of Interest Policy (Policy), the undersigned Official: 1. Affirms that Official has received or has access to, has read, and understands

the most current version of the Policy; 2. Agrees to comply with the Policy; 3. Based upon Official’s good faith belief, to the best of Official’s knowledge, and

except as disclosed below, certifies that Official currently complies with the Policy;

4. Discloses the following information or facts regarding any actual or potential income, employment, compensation, Conflicting Interest Transaction, Business Opportunity, or pecuniary benefit, or other information or fact, that could impact Official’s compliance with the Policy: ________________________________________________________________________ ________________________________________________________________________ _______________________________________________________________________;

5. Upon discovering any information or fact regarding any actual or potential income, employment, compensation, Conflicting Interest Transaction, Business Opportunity, or pecuniary benefit, or other information or fact, that could impact Official’s compliance, or another Official’s compliance, with the Policy, agrees to disclose this information or fact to Cooperative’s President or Manager; and

6. Upon not complying with the Policy, agrees to any sanction, disqualification, removal, or other action taken under the Policy.

___________________________________ ___________________________________ Printed Name of Official Signature of Official __________________________________ ___________________________________ Position of Official Date

Page 7 of 7

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-----Original Message----- From: Milton Hawkins Sent: Tuesday, January 04, 2011 8:40 AM To: Clement, Cristi Cc: Merle Moden; Ken Rigsbee; Ernest Altgelt; Jones, Dale Subject: My Take on the Strategic Issues Document Cristi, I'm not going to bother sending this anywhere else. You may do whatever you want with it. (I do think it's curious that anyone commenting on your issues document had to reveal his or her identity. What was the purpose of that?) This document is too detailed for a strategic exploration, and too general and vague to be an operational guide for near-term action, and it's the latter that we need NOW. What are you (I mean of course the Board) going to do about the Call Center/Member Services mess, about the ridiculous payment center operation, about credit card fees, about franchise fees, about taxes spread across the membership, about excessive retirement benefits, about a defined benefit plan run amok, about a KPI plan that's out of control, about too many managers, with too many car allowances, about too many coordinators, and too many supervisors, about too much advertising, about unnecessary matches to employees' giving, about excessive and wasteful Christmas spending, about a unified vehicle purchase policy, about directors' tasking staff without Board approval, about a dysfunctional committee structure, about excessive director compensation, and I could go on! I would reduce this document to a total of about twenty sentences under about six to eight headings. Put everything else in an operational plan, once you have one (if that day ever comes). But get the owners' permission before you venture further into generation, into more rebates and incentives, into a lifeline rate, etc. Understand what our relationship with LCRA is and what our contract with LCRA allows before you start tinkering with both. And let's quit talking about and trying to sell openness and transparency until we display a lot more in our month-to-month operations. It makes me so sick to think how badly things have been managed that I can barely stand to read what I've written. -- Milton Hawkins

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DRAFT APPROVED FOR COMMENT 12/20/10; FOR RELEASE JANUARY 3, 2011 Page 1 of 6

PEC Strategic Issues DRAFT APPROVED FOR COMMENT 12/20/10 Mission Statement: The purpose of the Cooperative is to provide safe, reliable, low-cost energy services in fiscally responsible partnership with its Member-owners.

1. Financial Issues A. Corporate Financial Model i. Develop and implement a rigorous corporate financial model for financial analysis, forecasting, planning, and reporting. This decision support system should provide timely insight into the financial implications of strategic and operational decisions.

B. Chief Financial Officer i. Develop and implement succession plan for CFO, with strong executive leadership skills and capable of process restructuring, in conjunction with hiring of CEO. [Skills and capable, as noun and verb, are not parallel. Is the CEO or the Board charged with this task?] ii. Recruit, develop and retain diverse financial expertise and advanced capability with consideration of Capability Maturity Model Integration (CMMI) or similar standard. [Who is to do this recruiting, developing, and training, the Board, or the CFO? Or is this still part of the description of the CFO?] iii. Emphasis on analytical, budgetary [what do these adjectives modify?], debt management, cost containment, ROI estimating and other analysis as required. [Emphasis is a noun, which doesn’t parallel with Develop and implement or Recruit, develop and retain. Who is to emphasize, and when, for what purpose?]

C. Budgeting and Financial Controls i. Management of a fair and equitable capital credits policy. [Management doesn’t parallel with the verbs in ii through ix. Who is to manage the policy?] ii. Manage budget variance to actual and identify and incorporate proposed adjustments and improvements into future budgeting. iii. Monitor PEC’s performance to industry benchmarks and identify opportunities to improve efficiency. iv. Implement financial controls to assure asset responsibility and to safeguard Member’s [Members’ (?)] money.

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v. Explore the feasibility of restructuring the Cooperative’s debt. vi. Perform a Cost/Benefits analysis of major programs, functional processes and services and prioritize competing initiatives. vii. Develop a mechanism for recommended [recommending (?)] improvements in operational efficiency and financial management policies. viii. Align and monitor [with and against what?] the Cooperative’s budget and ensure sustainability of net income. ix. Monitor and review Member assistance programs, credit and collection plans and write off [write-off (?)] policies against measurable results. DRAFT APPROVED FOR COMMENT 12/20/10; FOR RELEASE JANUARY 3, 2011 Page 2 of 6

D. Financial Ratios i. Monitor and achieve financial targets that are consistent with the Cooperative's goals and objectives. ii. Monitor and improve credit ratings objectives of the Cooperative. [Monitor and improve ratings, or objectives?]

E. SAP (LINKS) Implementation i. Maintain oversight responsibility, on-time delivery of the SAP (Links) system and achievement of PEC operational readiness coincidental with final acceptance of all contractual terms and conditions. [Maintain on-time delivery? Maintain achievement? Is PEC accepting contractual terms and conditions, and doing so at this late date! Or does PEC hope to accept on-time delivery from SAP of a product that meets all the terms and conditions of the contract?]

F. Procurement and Purchasing i. Develop, recruit, train and implement [. . . train and then utilize employees with (?)] procurement management skill sets. ii. Efficient management of procurement and purchasing decisions for major expenditures and investments. [Management doesn’t parallel the verbs of i and iii, and why limit efficient management to major items?] iii. Require efficient management of all post awarded [post-awarded (?)] contracts.

2. Rate Issues

A. Rate Design

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i. Reevaluate existing cost-of-service and rate structures with a focus on efficiency, equity, and fairness, the current business environment, and high quality [high-quality (?)] service through low-cost competitive rates. ii. Design rates to support energy efficiency, Demand Side Management (DSM) and distributed generation demanded by Members. [What exactly is being demanded by Members, all three things, two, or only distributed generation? And by how many members, a handful? thousands? Tens of thousands?] iii. Maintain unbundled rate structures to ensure accountability to Members by accurately passing through power purchase cost and the Cooperative’s cost of power delivery. iv. Develop a lifeline rate structure for qualified Members. [What is the projected cost to the cooperative? Shouldn’t we know before we undertake this mission?]

B. Rate Concerns i. Rate design criteria shall be established by the Board. [Sentences don’t parallel verb phrases. This is a strategic issue?] ii. Develop transparency on rates issues, and compare PEC’s rates with [those of (?)] other providers. iii. Demonstrate PEC’s competiveness and improve communication on those comparisons. iv. Inform Members about the rationale behind the rate structures. Develop a long term [long-term (?)] communication plan with measurable results to communicate rates in a method that is simple and understandable. [There is considerable overlap in ii, iii, and iv.] v. Ensure predictable, stable low-cost competitive rates for Members. [See II A i above.] DRAFT APPROVED FOR COMMENT 12/20/10; FOR RELEASE JANUARY 3, 2011 Page 3 of 6

3. Employee Issues A. Management i. Hire a CEO who understands the Cooperative model, recognizes the issues the Cooperative currently has before it, is an effective change agent and understands the unique role of PEC with its communities and employees. ii. Launch an effective communication plan to address re-structuring and re-alignment. iii. Reorganize the management structure to identify and develop personnel who have the leadership skills which best address the strategic goals and objectives of the Cooperative as set by the Board and produce measurable results tied to those goals. iv. Ensure that the Board and management are working together to provide a creative, constructive and safe working environment for the employees and Members.

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v. Develop a plan, to [plan to (?)] improve trust between [among (?)] employees, the Board and upper management, to [management to (?)] establish a unified PEC team. vi. Implement the actionable findings from Somerset Guild research and measure the results. vii. Create an environment for accountability that will build and improve the Cooperative through ongoing assessment and evaluation.

B. Employees i. Restructure the organization utilizing attrition and realignment of duties. ii. Prepare a staffing plan based on metrics consistent with the Cooperative’s goals and objectives and which will attract loyal high quality, progressive minded management and employees in a financially responsible manner. [based and which (?)] iii. Improve PEC’s employee’s [employees’ (?)] effectiveness, accountability and efficiency. iv. Implement changes with minimal disruption to Member operations. [What are Member operations?]

C. Compensation and Training i. Develop a comprehensive compensation plan, which ensures that PEC offers competitive compensation, benefits and professional development to retain valued employees. ii. Develop ongoing training for employees to understand the Cooperative business model and its application to serving the best interests of the Membership. iii. Ensure that the management and executive staff receives the training to manage changes at PEC and within the energy industry.

4. Organizational and Operational Issues A. Facilities i. Perform a full review of all facilities in which PEC has a presence to determine if a more cost-effective method exists to maintain PEC’s link to the community. [Why not to determine if there is a more cost-effective method of providing whatever essential service the facility was supposed to be providing? PEC already has an unmistakable link to every community: it’s a power line!] DRAFT APPROVED FOR COMMENT 12/20/10; FOR RELEASE JANUARY 3, 2011 Page 4 of 6

B. Organization Functions

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i. Effectively educate Members on what it means to be a Cooperative and how the Cooperative difference impacts Member’s [Members’ (?)] value. [Would anyone setting out to educate not try to do it effectively!] ii. Create an efficient forward thinking [efficient, forward-thinking (?)] organization prepared to address future challenges. iii. Perform a full review and analysis of the management and organizational structure of PEC to ensure [that (?)] the right people are in the right places for maximum effectiveness. iv. Implementation of [the (?)] Members Bill of Rights and bylaws [Bylaws (?)] into organizational policies and procedures. [Implementation doesn’t parallel with the verbs of the other paragraphs. [Implementation into policies and procedures?]

C. Operations Functions i. Identify and develop sound business cases for cost-effective outsourcing opportunities. ii. Coordinate decision-making processes to increase overall efficiency. iii. Update policies and procedures manual to ensure [that (?)] the best business practices are being implemented. iv. Establish meaningful performance metrics for controlling costs and improving productivity. v. Complete an operational benchmarking analysis and develop [a (?)] companywide process improvement plan and strategy.

5. Communication Issues A. Communications Department i. Develop, train, and recruit effective, high performance individuals to elevate PEC’s internal and external communications. ii. Yield [Create (?)] a greater Member understanding of cooperatives based on trust with an image of PEC as a desirable energy partner. iii. Develop and implement an effective communications strategy, both internally and externally, which is focused on PEC’s policies, procedures, directives and initiatives. iv. Review the communications department structure and activities for efficiency improvements.

B. Strategies i. Launch, maintain and update [a (?)] newly designed website and implement metrics to measure customer satisfaction, usage, and satisfaction of cost-efficiency goals through alternate billing, and other categories [?].

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ii. Develop cost-effective marketing strategies for PEC. iii. Assess Member needs and expectations through surveys and develop a plan to communicate to the membership those findings and action plans to address them. iv. Communicate that PEC is a leader among the Cooperative [?] in openness and transparency. [Is it?] v. Develop and improve a cohesive message in our communication efforts with policymakers, Members, stakeholders, media and the energy industry regarding PEC’s strategic issues and image. [Who are the stakeholders?] vi. Establish a plan for communicating emergency and disaster preparedness. DRAFT APPROVED FOR COMMENT 12/20/10; FOR RELEASE JANUARY 3, 2011 Page 5 of 6 vii. Develop a strategy toward proactive communications with Members, employees and media. viii. Develop a plan to respond [in a timely manner (?)] to questions raised by Members in meetings in a timely manner. ix. Highlight achievements of cooperatives and reinforce the value that PEC’s business model provides for the community.

6. Power Supply Issues A. Power Supply Providers i. Coordinate and integrate the Cooperative’s procurement of supply and demand side [supply-and-demand-side (?)] resources and incentives. [Procurement of incentives? And shouldn’t we first examine whether or not we need to offer or want to utilize incentives?] ii. Examine current and prospective power supply obligations and provide rigorous analysis of provisions of those agreements. [to what end, i.e., with what purpose in mind?] iii. Maximize the benefits and exercise effective management over long-term power supply contracts. iv. Understand the implications of opting into retail competition or complying with legislation requiring retail open access with respect to the Cooperative's obligations under the longterm [long-term (?)] power supply agreements. v. Develop a financial model of the Cooperative’s wholesale power purchase agreements to evaluate alternative resource management decisions. [What does alternative modfy?]

B. Power Supply Strategies

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i. Develop a least cost [least-cost (?)] integrated resource plan to achieve the renewable energy and other energy efficiency supply portfolio [?] goals. ii. Establish and develop a long-term power supply plan which yields a stable and affordable energy supply for the Membership by evaluating all sources of power and new technology. [Is the plan doing the evaluating?]

C. Demand Side Management i. Develop a portfolio of Demand Side Management (DSM) choices for Members in all customer classes. [And how many want this, and what will it cost to offer these choices? And are we not owner-members, rather than customers?] ii. Solicit Member feedback on the long-term energy resource plan to better manage Cooperative costs and retail bills, including, energy [including energy (?)] efficiency as a substitute for traditional generation. iii. Explore collaborative partnerships with new energy sources. [DOES THIS MEAN THAT WE’RE GOING INTO THE GENERATION BUSINESS?] iv. Revise and refresh renewable energy policies.

7. Member Services Issues A. Reliability, Customer [Member (?)] Service and Cost i. Provide safe reliable low cost [safe, reliable, low-cost (?)] electric service to the Cooperative’s Members. ii. Provide high quality [high-quality (?)] customer [Member (?)] service and reliability while balancing costs. iii. Maintain Customer [Member (?)] Service [service (?)] as the interface with the Members for problem solving and resolution. DRAFT APPROVED FOR COMMENT 12/20/10; FOR RELEASE JANUARY 3, 2011 Page 6 of 6 iv. Review the criteria and results of the JD Powers survey on reliability and rates [and (?)] then develop a plan for action on the findings. v. Review alternative sources for customer satisfaction information (Touchstone, CFC, NRECA, the Cooperative website or similar credible other [!] survey organizations).

B. Membership Involvement

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i. Establish an effective process for Member input on Cooperative products and services which supports Member control of [the (?)] Cooperative. ii. Deploy an ombudsman position [Employ an ombudsman to (?)] to advocate for member interests or problems associated with Member relations. [What do we have directors for! Why add another layer of bureaucracy, and at what cost?] iii. Educate Members on Cooperative [the Cooperative’s (?)] plans and goals and the business model. iv. Implement new bylaw [Bylaw (?)] changes and [the (?)] Member’s Bill of Rights [see 4 B 1v (Members Bill of Rights]. v. Review and enhance new services policies [?] including credit checks for deposit requirements, and line extensions. [credit checks for line extensions?] vi. Establish a paperless billing option. vii. Initiate process improvements that result in financial cost reductions to members [Members (?)].

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JANUARY 2011 SAFETY REPORT TO

THE PEC BOARD OF DIRECTORS

During the month of December:

o One Personal Injury Accident:• An employee pulled on gate and gate rolled over back of foot

o Four vehicle accidents reported:• A PEC vehicle hit a deer, employee was not injured.

• Adjusting mirror while parked on truck and it broke off

• Backed into tree branches and broke side mirror

• Bin door came open while driving, long stick slid out and hit on-coming vehicle

SAFETY INFORMATION - December 2010 2009

Number of Lost-time AccidentsThis Month 0 1

Year to Date *6 4Other OSHA This Month 0 0Reportable Injuries Year to Date 18 14

Number of Personal Injury AccidentsThis Month 1 1

Year to Date 16 23

Number of Vehicle AccidentsThis Month 4 1

Year to Date 25 13

Number of Employees TrainedThis Month 553 767

Year to Date 951 935

Class AttendanceThis Month 1,639 1,839

Year to Date 19,912 19,174

*All Lost Time Accidents are OSHA Reportable

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Month Jan Feb Mar Apr May June July Aug Sep Oct Nov DecSAIDI (min) 8.6 .8 3.1 3.0 4.0 8.2 1.9 2.8 4.3 1.8 2.5 4.5

SAIFI .13 0.03 .05 .04 .06 .11 .03 .05 .07 .04 .04 0.07

CAIDI (min) 64.3 29.4 58.9 75.8 62.2 74.3 61.7 58.3 58.6 48.0 65.1 66.6

Barksdale

Copperas Cove

Bertram

Devil's Hill

Spicewood

6 Sub Cirbuit Sw.Manchaca-BudaBlanco

Idle or disconnected $148 209 211

Total Year to Date 6073 6377 6751

Pending 1248 1343 1423

Completed 4677 4825 5117

158

NEW LINE EXTENSIONS

October November December

No Changes this month

December2

0.4

$19,324No Changes this month

November2

0.4

$19,324Estimated Cost

October4

4

$132,288

NumberApproximate Miles

OLD LINE EXTENSIONS

2010 DISTRIBUTION IMPROVEMENT PROJECTS

In ConstructionYTD CompletionsTotal Projects

44

98

Completed Projects

Rocksprings

Design Pending

Cedar Valley

RELIABILITY (Forced)

In DesignReady to Build

9

25Marshall Ford - Buttercup

SUBSTATION CONSTRUCTION PROJECTS

Dobyville 2

Marshall Ford Terminal

Dripping Springs

Phillips-Johnson City

Rutherford

Balcones

In ConstructionIn Design

Johnson City

WirtzAvery Ranch FeederHwy 183 Relocation

Avery Ranch

Buckner Boys Ranch

Andice

Operations Summary ReportDecember 2010

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Attachment: Operations Summary Report (December) (1506 : Monthly Operations Report)

Oct Nov Dec Oct Nov Dec172,88% 177, 91% 182, 93% 95,49% 98, 50% 99, 51%

6 feeders 6 feeders 8 feeders 18 feeders 15 feeders 15 feeders

17 12 5 59 59 67Remaining

Feeder Maintenance - Construction

Number of OutagesTotal Poles Inspected 2010

CompletedIn progressReady to be worked

Feeder Maintenance - Inspections

CompletedIn progress

Precentage of Poles Rejected 125

89

13,947

PrearrangedEquipment

Pole Inspection Program OutagesMembers affected

2012

10,616

1698

Buckners Boys Ranch substation was energized and placed in service.

276

2.0%

Unique Events

Total Poles Rejected

AnimalsFor the month of December the outages affected in all 17,872 members. The total outage time was 732 hours, with a member outage time of 19,056 hours.

Operations Summary ReportDecember 2010

Repairs were completed on the replacement of the T1 LTC at Buda, Unit will be placed in service Jan. 11th

264

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Attachment: Operations Summary Report (December) (1506 : Monthly Operations Report)

CONFIDENTIAL/CLOSED ITEM

(Pages 184-196)


(Pages 197-198)

SAIDI Indicator for KPI (Current period 2010 - 2011)

The following table and graph indicates the Statistical Interruption Time per Meter.This is also referred to as the System Average Interruption Duration Index or SAIDI.The number values represent Interruption Time in Hours.The time period is November 1 through October 31 for the KPI factor.Interruptions Exclude Planned, Transmission, and Major Weather and Events.

Interruption SAIDI Excluding Planned, Transmission, and Major Weather and Events

Year Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct08-09 0.05 0.14 0.20 0.24 0.31 0.41 0.48 0.64 0.71 0.78 0.84 0.9009-10 0.06 0.10 0.24 0.26 0.31 0.36 0.42 0.56 0.59 0.63 0.70 0.7310-11 0.04 0.12

0.00

0.25

0.50

0.75

1.00

1.25

1.50

1.75

2.00

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

SA

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08-09 SAIDI 09-10 SAIDI 10-11 SAIDI Platinum Gold Silver

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D_LIESMANN Pedernales Electric Cooperative, Inc.

Electric Outage Report (Cause)

Planned Outages Excluded Major Events Excluded

Beginning Date:12/01/2010 Ending Date:12/31/2010

District:All Districts Substation:All Substations

CauseNumber of

Consumers

Consumer

Outage Time

Actual

Outage Time

Number of

Outages

OutageType:Multiple Outage Types Device: Multiple Devices Cause:Multiple Causes

1 Animals 89 94:36 1698 974:47

2 Weather 35 54:36 792 1540:00

3 Equipment 125 223:56 10616 13277:04

7 Human Error 9 15:27 2754 1805:13

Totals 258 388:35 15860 17597:04

Consumer Hours:

Consumer Hours:

Consumer Hours:

Total Consumer Outage Time / Active Consumers

17597.067000 / 236997

0.07425

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Planned Outages Excluded Major Events Excluded



CauseNumber of

Consumers

Consumer

Outage Time

Actual

Outage Time

Number of

Outages

OutageType:Multiple Outage Types Device: Multiple Devices Cause:Multiple Causes

1 Animals 751 813:39 24090 17506:01

2 Weather 1989 3850:13 43714 62439:37

3 Equipment 1365 2433:29 69812 86179:27

7 Human Error 192 266:28 25461 11043:46

Totals 4297 7363:49 163077 177168:51

Consumer Hours:

Consumer Hours:

Consumer Hours:


177168.850000 / 236997

0.74755

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Planned Outages Included Major Events Included



CauseNumber of

Consumers

Consumer

Outage Time

Actual

Outage Time

Number of

Outages

OutageType:Multiple Outage Types Device: All Devices Cause:All Causes

1 Animals 89 94:36 1698 974:47

2 Weather 35 54:36 792 1540:00

3 Equipment 125 223:56 10616 13277:04

6 Scheduled 264 343:26 2012 1459:33

7 Human Error 9 15:27 2754 1805:13

Totals 522 732:01 17872 19056:37

Consumer Hours:

Consumer Hours:

Consumer Hours:


19056.617000 / 236997

0.08040

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Planned Outages Included Major Events Included



CauseNumber of

Consumers

Consumer

Outage Time

Actual

Outage Time

Number of

Outages

OutageType:Multiple Outage Types Device: All Devices Cause:All Causes

1 Animals 755 816:20 27498 17935:39

2 Weather 1991 3853:36 46577 62827:35

3 Equipment 1369 2436:56 74064 89309:59

4 Substation 3 3:14 1271 1598:56

5 Transmission 6 11:08 8071 14855:51

6 Scheduled 4579 5762:06 35604 33946:08

7 Human Error 201 272:09 34904 13766:57

Totals 8904 13155:29 227989 234241:05

Consumer Hours:

Consumer Hours:

Consumer Hours:


234241.083000 / 236997

0.98837

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Energy Usage and Average TemperatureRolling 2 Year Comparison (Monthly)

50,000,000

100,000,000

150,000,000

200,000,000

250,000,000

300,000,000

350,000,000

400,000,000

450,000,000

500,000,000

550,000,000

600,000,000

650,000,000

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

PE

C S

yste

m T

ota

l kW

h

40

50

60

70

80

90

100

Mo

nth

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vg. T

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. Deg

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F.

Monthly KWH - 1/09 thru 12/09 Monthly KWH - 1/10 thru 12/10

Average Temperature - 1/09 thru 12/09 Average Temperature - 1/10 thru 12/10

12.A.7

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Attachment: Temperature (Monthly) for December 2010 (1506 : Monthly Operations Report)

Weekly PEC System kWh vs Weekly Avg Air Temp

40,000,000

60,000,000

80,000,000

100,000,000

120,000,000

140,000,000

160,000,000

180,000,000

11/3

0/09

12/1

4/09

12/2

8/09

1/11

/10

1/25

/10

2/8/

10

2/22

/10

3/8/

10

3/22

/10

4/5/

10

4/19

/10

5/3/

10

5/17

/10

5/31

/10

6/14

/10

6/28

/10

7/12

/10

7/26

/10

8/9/

10

8/23

/10

9/6/

10

9/20

/10

10/4

/10

10/1

8/10

11/1

/10

11/1

5/10

11/2

9/10

12/1

3/10

12/2

7/10

Week Beginning With...

PE

C S

yste

m k

Wh

10

20

30

40

50

60

70

80

90

100

110

Avg

Air

Tem

per

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Air Temp.

PEC System kWh

PEC System kWh

Air Temp.

PEC System kWh

Air Temp.

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Attachment: Temperature (Weekly) for December 2010 (1506 : Monthly Operations Report)



Sponsors:


Updated: 1/19/2011 8:29 AM by Sylvia A. Romero A Page 1

Subject: 2011 Budget Presentation




• 2011 Budget Overview Jan2011_BOD (PDF)

• 2011 to 2014 CIP Memo 1-19-11 (PDF)

• CIP Presentation Board Meeting 1-24-11 (PDF)

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2011 Budget Presentation

RESOLVED BY THE BOARD OF DIRECTORS OF THE COOPERATIVE, that the 2011 Budget (Operating and Capital Improvement) is hereby approved and adopted as presented today.

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Pedernales Electric Cooperative

2011 Baseline2011 Baseline Operating Budget

January 2011

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Attachment: 2011 Budget Overview Jan2011_BOD (1505 : 2011 Budget Presentation)

2011 Budget Processg

Timeline: August – January Executive Team prioritized projects that will require resources over Executive Team prioritized projects that will require resources over

day-to-day operations Finance Team partnered with management to create first draft

budget for Octoberg Bottom-up budget, starting with current headcount & payroll

Executive Team reviewed total Company view, identified areas that needed further investigation and review Top-down adjustments recommended to managers Managers offered budget adjustments resulting in proposed budget flat to FY 2010

CEO final review: flat to 2010 did not demonstrate forward progress toward targets – spending reductions mandated:toward targets spending reductions mandated: 3% reduction in controllable costs 1% reduction in headcount from 2010

Presented to Financial Strategies Committee Jan 5

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Operating Budget Metricsp g gDec '09

PlanningTargets

FY2009

10+2 Adj2010

Proposed Budget

2011Targets 2009 2010 2011

Net Margin as a % of Operating Revenue 7%-8% 10% 9% 10% **

Net Margin ($000's) ------ $56,580 $46,828 $56,711

Controllable Expenses ($000's) Flat or < 2009 $105,910 $104,036 $98,731

Controllable Expenses per Meter ($) $425 $460 $444 $413

* Average Consumers per Employee 350 259 266 273

* Equity Ratio 30% 24% 27% 28%

* Planning targets to be met over multiple years.

** 10% resulting from baseline budget only Goal is 7% 8% after the BOD Strategic

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** 10% resulting from baseline budget only. Goal is 7% - 8% after the BOD Strategic

Plan is incorporated.

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2010 HighlightsEquity Rebuilding

• Rate redesign effective Aug’09 structured rates and line extension policy along industry standards

3% improvement

Power SupplyReduced power costs/kWh 15% while usage increased 3%; net savings $14MM

4.4% lower Cost of Power overall;• Reduced power costs/kWh 15% while usage increased 3%; net savings $14MM

• Renewable Generation Capacity increased by LCRA sourcing add’l 200MW windPower overall;Renewable Capacity now 23%

Debt Service Coverage• Used $25MM of CFC bridge, rather than $41MM budgeted

P id $18MM d bt i i l t hi h i t t t

Debt Svc Coverage2 27X

Net $7MM b d• Paid $18MM on debt principal at higher interest rate 2.27X

Bad Debt Expense Reduction• Improved and standardized collection policies & procedures• Outsourced and improved collections

$750k savings;Aged A/R > 60 days reduced 49%

borrowed

Right Sizing / Realignment• Reduced headcount through management of attrition 34 FTE reductions

• Maintaining reliability average service interruption < 1 hour

FINANCIAL GOALS WERE ACCOMPLISHED WHILE…• Maintaining reliability – average service interruption < 1 hour

• Upgrading capacity in 2 districts (>5,000 transformers, almost 500 miles of line)

• Reducing district offices’ inventory by $2.6MM

• Reducing reliance on contractors

4

• Closing one office (Georgetown)

• Increasing focus on safety with the establishment of a Committee and new procedures

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2011 Operating Initiatives & Assumptionsp g p

3% reduction in controllable costs from 2010; 1% reduction i h d t KPI b d $5MM iin headcount; KPI bonuses removed - $5MM savings Baseline budget net margin goes to 10% Overall goal of net margin is still 7-8%; reduction in controllable costs

creates funding for strategic initiativescreates funding for strategic initiatives

LINKS Phase I (ERP) live Labor Day 2011

Cost of Power Cost of Power Based on forecasted sales and power purchase costs; no margin impact

Centralized Tree Trimming Reporting Districts to have 2 contract crews; some funds kept at central operations Districts to have 2 contract crews; some funds kept at central operations

level for “as needed” basis – $1.5MM savings budgeted

Staffing/Payroll 2011 headcount 877 Full-Time Equivalent (FTE) positions Down from 886 at the end of 2010, and 920 at the end of 2009

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2011 Operating Initiatives & Assumptions (cont.)p g p ( )

Debt Principal repayment of $19MM scheduled November 2011p p y CFC Line of Credit (LOC) - $100MM capacity $50MM new debt assumed for 2011

Credit Card FeesA & Di l t d $800k i Amex & Discover no longer accepted: $800k savings

Other Items in Budget $ .96MM – Conservation (rebates); SEER qualification increased Jan ‘11 $ .50MM – Member Assistance Program $ .50MM Member Assistance Program $ .46MM – Community Giving Program + United Charities Match

• Maintaining reliability – average service interruption < 1 hour

• Continuing to focus on safety: hire a Safety Manager, improve reporting of safety issues

• Starting the implementation of a Board approved Strategic Plan

TO BE ACCOMPLISHED WHILE…

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• Starting the implementation of a Board-approved Strategic Plan

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Consolidated Income Statement(NOTE: $ presented in 000's) 10+2 Adj PROPOSED DELTA

FY 2010 BUDGET 2011 vs2009 Note 2011 2010 10+2 Adj %

kWh Sales 4,717,712,775 4,847,617,036 4,913,027,125 65,410,089 1%kWh Sales 4,717,712,775 4,847,617,036 4,913,027,125 65,410,089 1%

OPERATING REVENUES Sales of Electricity 540,432$ 520,653$ 544,456$ 23,802$ 5% Other Revenue 30,729 27,018 28,662 1,644 6%Total Operating Revenues 571,161 547,672 573,117 25,446 5%

OPERATING EXPENSES Cost of Power 327,941 313,559 331,474 17,914 6%, , , , % Transmission 1,596 1,554 2,327 773 50% Distribution Op 21,854 22,778 21,273 (1,505) -7% Distribution Maint 18,818 17,799 15,291 (2,508) -14% Consumer Accounts 29,250 27,281 28,214 933 3% Consum Svc & Info 2,072 2,454 2,803 349 14% Economic Develop 1,971 1,491 1,750 259 17%

Controllable Expenses

Admin & General 31,944 32,232 29,399 (2,833) -9% Depreciation 36,706 38,254 38,522 269 1% Taxes 5,346 5,373 5,471 98 2%Total Operating Expenses 477,499 462,776 476,524 13,748 3%

Total Controllable Expenses 105,910 104,036 98,731 (5,306) -5%

OPERATING MARGIN 93,662 84,896 96,593 11,697 14%, , , , %

Interest Expense 41,485 40,321 39,763 (558) -1%

Other Income(Expense) 6,348 2,253 (119) (2,372) -105%

Discontinued Operations (1,946) - - - 0%

NET MARGIN 56,580$ 46,828$ 56,711$ 9,883$ 21%,$ ,$ ,$ ,$

Note: "10 + 2 Adj" represents 10 months of actual data plus 2 months of updated forecast data

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Operating Statisticsp gCFC LG CUST FY FY 2010 PROPOSED2009 MEDIAN 2009 (10 + 2 Adj) 2011 BUDGET

KWH Purchases N/A 5,052,727,765 5,204,734,158 5,263,157,278 KWH Sales 3,137,594,000 4,717,712,775 4,847,617,036 4,913,027,125KWH Sales 3,137,594,000 4,717,712,775 4,847,617,036 4,913,027,125

Purchased Power as a % of Electric Revenue N/A 60.7% 60.2% 60.9%

Residential Usage per Total KWH Sold 67.2% 69.9% 72.1% 69.4%Residential Meters per Total Meters N/A 91.0% 90.9% 91.3%Average Residential KWH Usage per Month 1,152 1,311 1,362 1,302

GROWTH:KWH Sales Growth 2 0% 0 8% 2 8% 1 3%KWH Sales Growth -2.0% 0.8% 2.8% 1.3%Consumer Growth 0.5% 2.5% 1.8% 1.9%

KWH:Electric Revenue per KWH Sold $0.10644 $0.11455 $0.10740 $0.11082Purchased Power per KWH Sold N/A $0.06951 $0.06468 $0.06747Gross Margin per KWH Sold N/A $0.04504 $0.04272 $0.04335

Controllable Expenses per KWH Sold $0.01508 $0.02245 $0.02146 $0.02010Co t o ab e pe ses pe So d $0 0 508 $0 0 5 $0 0 6 $0 0 0 0

METER:Average Meters 148,006 230,446 234,577 239,034 Controllable Expenses per Meter (1) $278.53 $459.59 $443.51 $413.04

MOL:Total Miles of Line 8,869 17,074 17,250 17,386 Average Meters per Mile of Line 17.3 13.5 13.6 13.7

EMPLOYEE:Total Full Time Employees (2) 291 889 882 875 Average Consumers per Employee 495 259 266 273

* Notes:

2010 10 + 2 Adj numbers represent 10 months actual and 2 months of reforecasted amounts. PEC metrics are calculated from PEC Consolidated financials. Amounts reported to CFC are for PEC (unconsolidated) only.

(2) Employee counts for 2009 and 2010 represent full-time employee counts at December and October respectively.

(1) For comparison purposes to CFC KRTA, transmisson expense was excluded from controllable expenses (CFC includes transmission expense as a component of power cost).

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Operating Expense as % of Revenuep g p

2010 (10 + 2) 2011 Budget

9%

2010 (10 + 2)

10%

2011 Budget

11%

7%

9%

10%

6%

10%

57%

7%58%

7%

9% 9% Cost of Power

Labor & Fringe Benefits Expense

Depreciation Expense

Other Operating Expense

Interest Expense and Other

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Net Margin

Note: Cost of Power as a % of Electric Revenue = 60.2% in 2010 and 60.9% in 2011as noted on the Operating Statistics page 8

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Debt Service CoveragegProposed

(NOTE: $ presented in 000's) FY Rolling 12 Budget2009 October 2010 2011

REVENUES: Operating Revenues 571,161$ 551,733$ 573,117$ Interest & Dividend Income 1,870 2,137 902 Capital Credits 2,385 1,632 1,000 Total Revenues 575,416$ 555,503$ 575,019$

EXPENSES: Operating Expenses 477,499$ 465,016$ 476,524$ Less: Depreciation (36,706) (38,384) (38,522) Less: Post Retire Medical Benefit (3,763) (4,381) (4,713) Plus: Other Deductions 546 438 175 T t l E 437 576$ 422 689$ 433 464$Total Expenses 437,576$ 422,689$ 433,464$

NET REVENUES 137,840$ 132,814$ 141,556$

Long Term Debt Service 58,639 58,592$ 57,572$ SURPLUS (DEFICIT) 79,201$ 74,222$ 83,983$

DEBT SERVICE COVERAGE 2.35 2.27 2.46 *

Notes:Bond covenant threshold = 1.15Bridge Loan covenant threshold = 1 35

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Bridge Loan covenant threshold 1.35* 2.46 coverage is the result from the baseline budget, which has a net margin of 10%.

The goal of reducing the net margins to 7% to 8% would reduce DSC by 0.2 to 0.3 points.

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FunctionalResponsibilities

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Expense by Departmentp y p

2010 (10 + 2) 2011 Budget

20%

1%

1%

1%

21%

2%1%

1%

1%

20%

63%

8%

3%

2%65%

7%

3%

Power SupplyOperationsMember ServicesStrategic InitiativesFinancial Services

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Financial ServicesCEOGeneral CounselPEC Corp

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Power Supply – Dale Jones pp y J Overview

Monitors ERCOT power markets and regulatory issues for downstream risks and t ti l i t t PECpotential impacts to PEC

Routinely evaluates power supply portfolio and analyzes alternate supply options for potential lower cost reliable power options in accordance with LCRA contract terms with recommendations to BOD

Supports Strategic Initiatives and Operations in the evaluation and promotion of Supports Strategic Initiatives and Operations in the evaluation and promotion of progressive power activities

Cost Drivers Energy requirements (total energy and time of use) Energy requirements (total energy and time of use) Fuel Costs (natural gas/coal) LCRA costs (fuel/non-fuel)

Significant Initiatives Significant Initiatives Continue active participation in LCRA’s resource and business planning process

representing PEC’s goals and objectives Continue to proactively evaluate customer supply and progressive power

opportunities in accordance with LCRA contract termspp Manage a transmission cost of service study for filing at the PUCT for additional

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Operations – Paul Hilgersp g

Overview System Engineering – Manages the capital plan; designs, builds and System Engineering Manages the capital plan; designs, builds and

maintains transmission lines and substations Technical Communications – Telecommunications & SCADA District Operations - Member services planners, construction, service &

maintenance warehouse and member services representatives (see p15)maintenance, warehouse, and member services representatives (see p15)

Cost Drivers Payrolly Telecommunications Transportation District Offices – facilities costs

Significant Budget Issues Goal - Reduce costs and identify efficiencies while maintaining focus on

reliability and safetyreliability and safety Tree Trimming - reduced by $1.5MM from 2010

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Operations – District Functionsp

Member Services Planners – new member applications, line maintenance including inspections & design of extensions, map maintenanceg p g , p

Construction – construct line extensions & system improvements, 1st

responders on after hour outages

Service / Maintenance – perform system maintenance, install new services, respond to outages during business hours, analyze & remedy voltage irregularities

Warehouse – manage inventory, support construction & service crews by readying materials for jobs, oversee maintenance of fleet, buildings and groundsgrounds

Member Services Representatives – assist members on billing, payment & service requests, manage delinquent accounts

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Member Services – James BlantonJ Overview

IT – manages all computer hardware purchases for co-op in addition to all software maintenance contracts

Member Services – call center for member support Human Resources – employee relations Purchasing central purchasing for all capital and expense items Purchasing – central purchasing for all capital and expense items

Cost Drivers Payroll Payroll Software Maintenance contracts Growth-driven computer hardware purchases

Significant Budget Issues Call center reduced by 6 FTEs through attrition $287k new maintenance expense, primarily SAP

d d b d ll ff b d ll Bad debt system and collection costs were offset by increased collections

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Strategic Initiatives – Jeanell Davisg J Overview

Manages internal and external communications – media relations, press releases, website member communications and community programs re: safety and website, member communications, and community programs re: safety and conservation

Interacts with members regarding all energy efficiency matters, including rebates and audits

Handles all written member correspondence including district operations Handles all written member correspondence including district operations communications, responses to letters, and website replies

Offers community training, grant-writing assistance to civic organizations Manages headquarter facilities maintenance and support

Cost Drivers Payroll Postage (mass mailings and Texas Co-op Power) Rebates for HVAC and commercial lighting programs Rebates for HVAC and commercial lighting programs

Significant Budget Issues Website implementation in 2010; lower expense for enhancements planned for 2011 Communications and public relations for Capital Credits paid-out with new policy Communications and public relations for Capital Credits paid out with new policy

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Chief Executive Officer – Luis A. Garcia

OverviewOversight of the Company’s day to day operations Oversight of the Company’s day-to-day operations

Board related expenses Includes executive team members (direct reports to CEO) with

the exception of Finance General Counsel Power Supplythe exception of Finance, General Counsel, Power Supply

Cost DriversPayroll Payroll

Board election services & compensation Membership dues – i.e. NRECA, TEC, Touchstone, etc.

Some co po ate le el p ojects/spending s ch as Inte nal A dit Some corporate-level projects/spending such as Internal Audit

Significant Budget Issuesh f h f Search for new CEO – search fees

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General Counsel – Aisha Hageng

Overview Advisor to Cooperative, work through Board & CEO and respond to all districts & p , g p

departments Governance of co-op: contract review, open records requests, whistleblower claims,

compliance management, risk management Oversight of third-party specialist law firms Pole Contacts: Ensure proper and safe attachments to PEC’s facilities

Cost Drivers Insurance Payroll Outside Counsel fees Pole Contacts provide a revenue source; $500k increase due to higher rates and

additional pole contacts ($4.2MM budget)p ($ g )

Significant Budget Issues Vacant headcount pending CEO decision Decreased reliance on outside counsel from 2010 (due to LINKS negotiations) Decreased reliance on outside counsel from 2010 (due to LINKS negotiations)

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Financial Services – Mike Vollmer Overview

External financial reporting to members and regulatory bodiesp g g y Funding of Company operations (debt management) Internal (management) reporting Budgeting and financial analysis Support of finance-related initiatives such as Internal Audit, rate

redesign

Cost Drivers Payroll Bank, audit, and credit card fees LINKS

Significant Budget Issues LINKS $2.6MM expense: Deloitte and internal resources – training and

data conversiondata conversion Amex & Discover no longer accepted: $800k savings

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PEC Corporate – Mike Vollmerp Overview

Central reporting of co-op wide costs, particularly those less p g p , p ydiscretionary in nature

Includes some non-cash items such as depreciation

Cost Drivers Cost Drivers Capital expenditures (depreciation expense) Interest expense Payroll related corporate expenses – pension & post retirement medicaly p p p p Franchise fees Property taxes Member Assistance Program

Significant Budget Issues KPI removed from 2011 budget Franchise fees subject to negotiations with municipalities Franchise fees subject to negotiations with municipalities Interest will be based on actual borrowings from CFC bridge loan

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Appendixpp

A. Community Givingy gB. Glossary of Terms

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A. Community Giving y g

Approved ProposedActual Budget 10 +2 Adj BudgetActual Budget 10 +2 Adj Budget

2009 2010 2010 2011

Community Giving Program (CGP):

Light the Way $ 160,000 $ 160,000 $ 156,500 $ 160,000

PEC Scholarship Fund 46 700 38 500 37 000 50 000PEC Scholarship Fund 46,700 38,500 37,000 50,000

Project Graduation 17,250 17,500 19,000 17,500

Livestock Show Support (FFA & 4-H) 16,000 17,500 17,000 17,100

Partners in Learning - 15,000 17,000 17,000

CGP Application Support - - - 25,000CGP Application Support 25,000

$ 239,950 $ 248,500 $ 246,500 $ 286,600

PEC United Charities-Corporate-Matched Funds 173,486 174,000 165,000 175,000

Total Charitable Contributions $ 413,436 $ 422,500 $ 411,500 $ 461,600

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B. Glossary of TermsyAccounting & FERC-Related Terms

Transmission – Operation and maintenance costs for transmission lines which, are required to transmit power through the Cooperative and to PEC substations Most transmission expenses are included in System through the Cooperative and to PEC substations. Most transmission expenses are included in System Engineering in Operations.

Distribution Operations – Current period costs to keep power flowing through the system in the required amounts (i.e. operating performance). This includes all routine operation of overhead and underground lines, street lighting, meters, installation, load dispatching, and substation operations, including personnel-related expenses. Examples include routine functions of SCADA and restoring power due to an outageExamples include routine functions of SCADA and restoring power due to an outage.

Distribution Maintenance – Maintenance expenses are normal and recurring work performed specifically for the purpose of preventing failure, restoring serviceability, or maintaining the life of the plant. These include maintenance of overhead and underground lines, and other buildings and equipment, including personnel-related expenses. Includes recurring tree trimming and other planned preventative maintenance.

Consumer Accounts – Member account assistance costs related to meter reading, bad debt, and the member assistance program (MAP). Call center expenses and district front offices are accounted for in this category.

Consumer Services & Information – Consumer service costs for activities which focus on encouraging safe, efficient and economical use of the utility’s service. Also includes safety related messaging.

Economic Development – Community activities expense for promoting or retaining the use of utility services by present and prospective members. Includes member educational programs and training costs.

Administrative & General – General administration expenses of the utility’s operations that are not specifically provided for in other accounts and costs that are by nature a corporate or administrative function. This includes human resources, finance, and general counsel functions along with directors fees and data processing.

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, , g g p g

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B. Glossary of Terms, cont’dyDepreciation Expense – Required accounting recognition of the current period depletion of long-term assets.

Taxes – Property (real property and equipment) taxes and franchise fees are included in this category.

Interest – Interest on long-term debt, including bond issues and other interest expense, such as CFC line of credit and lease agreements.

Other Income & Expenses – All other income and expenses not classified elsewhere, such as interest income from bank accounts, charitable contributions, and legal settlements.

ERCOT – Electric Reliability Council of Texas is the independent system operator of the Texas electric grid. They manage the deregulated market for 75 percent of the state, holding daily auctions to identify lowest cost providers for suppliers to meet load requirements.

SCADA – Substation Control and Data Acquisition is a communication system which allows monitoring of the distribution system so adjustments can be made in the operation of certain equipment from the central control distribution system so adjustments can be made in the operation of certain equipment from the central control facility in Johnson City.

SEER – Seasonal Energy Efficiency Ratio is a standard measurement of overall efficiency of a heat pump or air conditioner. The higher the SEER, the more efficient the unit.

SAIDI – System Average Interruption Duration Index measures the minutes of outage experienced by the average SAIDI System Average Interruption Duration Index measures the minutes of outage experienced by the average member during a one-year period.

PUCT – Public Utility Commission of Texas – The state agency created to regulate utilities in Texas, which assures that rates, operations, and service are just and reasonable to the consumers and the utility companies.

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January 19, 2011 TO: Luis Garcia FROM: Paul Hilgers SUBJECT: 2011 to 2014 Capital Improvement Plan (CIP) The 2011 - 2014 Draft CIP was revised December 21, 2010 to accurately reflect General Plant additions as follows (page 8):

CIP 2011 2012 2013 2014 Electric $72,289,727 $48,983,491 $44,552,798 $57,995,942 GP $31,325,405 $20,030,471 $14,430,508 $9,708,701 Total $107,615,132 $69,013,962 $58,983,306 $67,704,643

Since that date, two projects totaling $20,000 were added in General Plant. The first of these was $10,000 for power quality test equipment for System Engineering, and the other was $10,000 for a new display booth for Communications. In addition, Substation design has added a project for 2011 and has adjusted the schedule for several other projects which affected the amounts for 2011 through 2014. The revised totals for these above changes are reflected below.

CIP 2011 2012 2013 2014 Electric $72,437,177 $48,686,041 $42,952,798 $58,295,942 GP $35,345,405 $20,030,471 $14,430,508 $9,708,701 Total $107,782,582 $68,716,512 $57,383,306 $68,004,642

Because these changes affect multiple sheets throughout the printed version of the CIP and materially only amount to $297,450 of the amount for 2011, we have not printed revised copies. These changes are reflected in the presentation scheduled for the January 24 Board Meeting and revised copies will be provided upon approval by the Board. If you have any questions, please call. Paul Hilgers Deputy General Manager PH:RP:caf cc: Executive Team

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Capital Improvement Plan

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January 24, 2011


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Attachment: CIP Presentation Board Meeting 1-24-11 (1505 : 2011 Budget Presentation)

2011 – 2014 Capital Improvement Plan

• Elements

• Summary

• Criteria

• Questions?

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• Introduction• Summaries

– Cooperative– Electric System– General Plant

• Detail• Project Descriptions• Planning Criteria

Elements

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Summary

$141.1

$13.6

$127.5

2008 20142013201220112010 2009

$9.7$14.4$20.0$35.3$14.1$12.9General Plant

$68.0$57.4$68.7$107.8$94.8$133.9Total

$58.3$43.0$48.7$72.4$80.7$121.0Electric System

Note: All amounts are in millions. 2008 thru 2010 are actual amounts taken to plant.

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2011 – 2014 Capital Improvement PlanPer Category in $Million

0

20

40

60

80

100

120

140

160

2008 2010 2012 2014

Electric

General

Total

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2011 – 2014 Capital Improvement PlanBy Electric Category in $Million

-20

0

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40

60

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120

140

2008 2010 2012 2014

Transmission

Substation

Distribution

Total

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Electric System– 2008 to 2011, reduction of $55.1 Million

– 2009 to 2011, reduction of $48.6 Million


• Overall– 2008 to 2011, reduction of $33.3 Million


– 2010 to 2011, increase of $13.0 Million

Changes

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2011 Capital Improvement Plan

• Provides a brief description of the Projects

• 167 Electric Plant projects- 2 Transmission Projects- 54 Substation Projects- 111 Distribution Projects (16 from 2010)

• 72 General Plant projects

Project Descriptions

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00.5

11.5

22.5

33.5

44.5

5

1st Qtr

Kyle Buda

Marble Falls

Johnson City

Junction

Canyon Lake

Liberty Hill

Oak Hill

Cedar Park

Bertram

Distribution System Improvement Projects by District($Millions)

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Questions?

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GROWTH STATISTICS

YEAR/ ACTIVE NETMONTH ACCOUNTS* INCREASE APPLICATIONS

2008January 221,799 523 3,593February 222,430 631 3,717March 223,190 760 4,000April 223,958 768 3,972May 224,660 702 4,224June 225,331 671 4,356July 225,839 508 4,632August 226,271 432 4,711September 226,764 493 3,848October 227,112 348 3,602November 227,506 394 2,625December 227,890 384 3,315



*"Active Accounts" was formerly identifed as "Number of Consumers." Active Accounts are meters and lights only.

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SUMMARY OF ALL NEW ORDERS, NEWLY ADDED ORDERS, AND BLANKET RELEASES

January 1 - December 31, 2010

No. of New Orders,Newly Added Orders,and Blanket Releases

Contract Amt or EstimateAmt Paid AmtRmng

$6,078,280.06$5,964,541.36 $113,738.70495January 2010

$2,695,197.07$2,610,860.01 $84,337.06513February 2010

$4,060,016.46$3,424,595.33 $635,421.13517March 2010

$22,310,294.54$8,265,299.11 $14,044,995.43615April 2010

$4,078,377.26$3,423,982.26 $654,395.00566May 2010

$6,242,375.35$5,398,277.28 $844,098.07475June 2010

$8,552,425.49$4,016,563.59 $4,535,861.90553July 2010

$3,201,443.74$2,435,530.70 $765,913.04518August 2010

$8,299,682.25$3,888,342.74 $4,411,339.51527September 2010

$4,332,267.12$2,825,983.90 $1,506,283.22405October 2010

$7,637,495.32$3,180,141.69 $4,457,353.63315November 2010

$24,840,931.39$1,859,534.61 $22,981,396.78454December 2010

$102,328,786.05Purchase Orders Totals: 5,953 $47,293,652.57 $55,035,133.48

Page 1 of 1

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Object Object Description Payee Amount

PEDERNALES ELECTRIC COOPERATIVE, INC.OVER $10,000 VOUCHED TO THE MONTH OF DECEMBER 2010

Summarized and Grouped by GL Account & Payee

Page 1 of 5

126 DP-OH Conductors & Devices

K B S Electrical Distributors 45,880.00

45,880.00Sub-Total by Object131 DP-Line Transformers

TEC Utility Supply & Service 200,615.00

200,615.00Sub-Total by Object134 DP-Meters

Stuart C. Irby Company 24,250.00

24,250.00Sub-Total by Object154 GP-Structures & Improvements

Westhill Paving Inc 22,732.50

22,732.50Sub-Total by Object156 GP-Comp Equip & Software

Sigma Solutions 50,625.30

50,625.30Sub-Total by Object158 GP-Transp Equip (w/o Hvy Eq)

Grande Truck Center 66,898.00

Gunn Chevrolet-Dodge-GMC 17,612.15

84,510.15Sub-Total by Object163 GP-Power-Operated Eq (inc Veh)

American Test Center 15,500.00

Nesco Inc 119,597.00

135,097.00Sub-Total by Object187 WIP-Dist Overhead

HD Supply, Inc. 10,800.00

10,800.00Sub-Total by Object188 WIP-Dist Contractor Services

Can-fer Utility Services LLC 143,432.87

Eckhardt Elect Const Inc 21,408.59

Infrastrux T & D Services 43,229.54

Pike Electric LLC 127,316.29

T & D Solutions LLC 441,704.88

T & D Solutions, Ltd 78,640.10

855,732.27Sub-Total by Object199 WIP-LT Contractor Serv

Adjacent Technologies Inc 194,496.00

Deloitte Consulting, LLP 1,327,784.94

15.A.1.b

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Delta Star 714,482.00

Lambda Construction I Ltd 348,560.00

North Houston Pole Line, LP 661,635.20

Pascor Atlantic Corporation 24,864.00


Techline Ltd 146,624.00

Thomas & Betts Corporation 441,482.00

Tidal Power Services LLC 43,578.44

Valmont/Newmark (Concrete) 209,227.00

4,195,421.71Sub-Total by Object454 Materials Inventory-Stocked

K B S Electrical Distributors 104,600.00

TEC Utility Supply & Service 179,104.47

Techline Ltd 30,260.00

Texas Electric Cooperatives In 200,391.90

514,356.37Sub-Total by Object468 Stores Exp-Clearing

Time Warner Cable 33,456.42

33,456.42Sub-Total by Object481 Prepaid Insurance

Blais Insurance Services 15,500.00

15,500.00Sub-Total by Object482 Prepaid Ins-Worker's Comp

Texas Mutual Insurance Company 19,497.00

19,497.00Sub-Total by Object484 Prepaid Maint Agreement

AtTask, Inc. 80,112.00

80,112.00Sub-Total by Object485 Prepaid Premium-Employee Insur

Blue Cross & Blue Shield of Te 827,066.45

Guardian Life Insurance Compan 59,013.43

Life Insurance Company of Nort 98,984.17

985,064.05Sub-Total by Object496 Transportation-Clearing

Stroeher & Son Inc 29,660.44

Wright Express 10,079.90

39,740.34Sub-Total by Object500 Misc Def Debit-Fixed Pension

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Frost National Bank 6,235,000.00

6,235,000.00Sub-Total by Object694 COP-Purchased For Resale

AEP Energy Partners Inc 4,741,092.98

Lower Colorado River Authority 15,984,388.45

20,725,481.43Sub-Total by Object721 TME-Substation Equipment


30,113.75Sub-Total by Object745 DOE-Misc Distribution Expense

Best Buy For Business Austin/C -1,022.82

-1,022.82Sub-Total by Object760 DME-Poles, Towers & Fixtures

Davey Resource Group 21,280.64

Osmose Utilities Services Inc 65,307.05

86,587.69Sub-Total by Object762 DME-O/H Pole Mtd Transform


16,450.00Sub-Total by Object766 DME-Tree Trimming

National Tree Expert Company I 60,872.64

60,872.64Sub-Total by Object778 Consumer Assist & Records

ClearTran 10,967.63

Information Management Solutio 26,088.24

Time Warner Cable 83,641.03

USPS-CAPS # 21253 100,000.00

USPS-POC #1829830 15,000.00

235,696.90Sub-Total by Object793 Instruct Adver


61,081.60Sub-Total by Object810 Eco Dev-Info Prog

Christmas Light Company Inc 34,500.00

34,500.00Sub-Total by Object820 A&G-Office Supplies

CustomGuide Inc 15,245.00

15,245.00Sub-Total by Object821 A&G-Contract Services

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BKD 24,675.00

Bridgepoint Consulting 37,824.50

Tocquigny 22,500.00

84,999.50Sub-Total by Object824 A&G-Injuries & Damages

Vogels, The 12,400.00

12,400.00Sub-Total by Object826 A&G-Emp Pension & Benefits

Rudd and Wisdom Inc 13,169.50

13,169.50Sub-Total by Object827 A&G-Health & Medical

McQueary Henry Bowles Troy LLP 31,000.00

31,000.00Sub-Total by Object837 A&G-Data Processing

CompUSA 13,485.00

Comsys 11,692.80

Deloitte Consulting, LLP 55,840.24

NetWrix Corporation 14,850.00

Sigma Solutions 22,000.00

117,868.04Sub-Total by Object839 A&G-Rent & Lease Expense

Lane LTD, Robb 10,968.33

10,968.33Sub-Total by Object840 A&G-Maintenance-General Plant

Goff Services 13,231.40

13,231.40Sub-Total by Object842 A&G-Credit Card Clearing

Commercial Card Solutions 133,597.91

133,597.91Sub-Total by Object844 A&G-Telephone Voucher Clearing

A T & T 10,618.78

A T & T Mobility 12,373.03

Verizon Wireless 37,678.96

60,670.77Sub-Total by Object846 Legal Expenses

Cox Smith Matthews Inc 18,435.00

18,435.00Sub-Total by Object951 Misc Non-Oper Income-Expense

Opus Real Estate VIII LP 15,350.00

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15,350.00Sub-Total by Object954 Oth Deducts-Donations

P E C United Charities Inc 13,408.14

13,408.14Sub-Total by Object 35,338,494.89

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(Page 343)


(Pages 344-346)

This Month 0.08040 0.05584Year To Date 0.98837 1.00926

Interruption Hours excluding planned, This Month 0.07425 0.04394 transmission, and major weather outages Year To Date 0.74755 0.84299

2010 2009

This Month 0 1Year To Date 21 19

This Month $0 $14,500Year to Date $466,138 $510,553

This Month 12 38Year To Date 551 739

This Month $118,000 $69,575Year To Date $1,364,150 $986,400

This Month $0 $4,155Year To Date $87,293 $34,065

2010 2009This Month 68 44

Year to Date 554 367

15,451 75,1445.01 5.37

0:02:46 0:04:18

95,591 96,8575,785 24,543

$ 1,242,318.99 3,183,723.32$ 5,580 15,714

Total Service Request (Top Three) N/A 2,736N/A 1,542N/A 727

N/A 467Total Video Views N/A 233

2010

Total Interruption Hours

2009DECEMBERCONSUMER POWER INTERRUPTION HOURS

COMMUNITY RELATIONS - DECEMBER

Number of Grants Funded

Total Amount of Grants Funded

Total Sessions

Energy Audits Completed

CONSERVATION:

PROGRAMS - DECEMBERNumber of Programs Presented

December 1-5 December 6-31

COMMUNITY DEVELOPMENT:

MyUse Activity (Number of Reports including Notifications)

PEC WEB SITE - DECEMBER

Payment Total for Month

Average Pageviews per visitAverage Length of Session (HH:MM:SS)

Accounts Registered To-DatePayment Count for Month

Commercial Lighting Rebates $ Paid

HVAC Rebates $ Paid

Change Contact Information

The above numbers represent statistics from the previous and current websites. A new report format will be created for January statistics.

Auto Payment AgreementsPaperless Billing

P:\Board Reports\BOARD REPORTS FOR 2011-01-24

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PEC Audit Committee PO Box 1 Johnson City, TX 78636

Committee Meeting www.pec.coop

~ Minutes ~ Call PEC Toll Free 1-888- 554-4732

Friday, November 19, 2010 3:00 PM PEC Board Room 201 South Avenue F Johnson City, TX 78636

PEC Audit Committee Page 1 Revised 1/13/2011

I. Call to Order 3:00 PM Meeting was called to order at 3:40 PM on November 19, 2010 at PEC Board Room, 201 South Avenue F, Johnson City, TX.

Attendee Name Title Status Arrived Kathryn Scanlon Committee Chairperson Present Cristi Clement Committee Member Present Ross Fischer Committee Member Present James Blanton Assistant General Manager Present Luis Garcia Acting General Manager Present Mike Vollmer Chief Financial Officer Present Aisha Hagen Acting General Counsel Present Eddie Dauterive Member Services Manager Present Zelenny Martinez Information Technology Manager Present Theresa Owens HR Manager Present Elaine Olaez Accounting Coordinator Present Pamela Anderson HR Supervisor Present Tia Owens Administrative Assistant Present Jeff Dempsey Bridgepoint Consulting Present Tim Martin Deloitte Consulting Present

II. Review and Approve Minutes Approval of the October 29, 2010 minutes was suspended until next meeting.

III. Member Comments

IV. Open Session

A. Unfinished Business

i. LINKS Update

Mike Vollmer and Tim Martin gave the update on the LINKS project. The project is progressing on track. Mr. Vollmer reported that PEC is working with Deloitte on the change order to the contract to separate the implementation of the CRB and ERP phases of the project. Once the change order has been reviewed by both sides and legal, it will be brought back to the committee and eventually the whole Board for approval. PEC has internally filled the position of Process Control for the project. Also, a third party Project Manager with SAP implementation experience, Zubin Billimoria, has been selected and will be joining the team soon.

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Committee Meeting Minutes November 19, 2010

PEC Audit Committee Page 2 Revised 1/13/2011

B. New Business Director Scanlon would like the Board to give the Audit Committee Chair authority to sign the Audit Engagement Letter from BKD in the future. It was confirmed that this would not affect the Delegation of Authority of the Board. Action: Ms. Hagen will draft a resolution to the Board delegating the Audit Committee Chair authority to sign the Audit Engagement Letter for the Cooperative.

V. Closed Session The closed session was called to order at 4:06 p.m., CDT.

A. Competitive Matters

i. Update on Internal Audit and Corrective Action List

ii. Risk Assessment Status Report

B. Personnel

i. Defined Benefit Design

VI. Reconvene Open Session Funding of the Defined Benefit Plan: Upon the recommendation of the Plan's actuary, as reported by Theresa Owens, the Audit Committee unanimously approved a recommendation that the Cooperative make a $6,235,000 contribution to the Plan before the end of 2010. Action: The Committee directed staff to prepare a resolution authorizing this contribution for the Board's consideration. Bridgepoint Consulting retested the Cooperative's WhistleBlower policy and it received the highest rating.

VII. Adjournment There being no further business to come before the PEC Audit Committee, meeting was adjourned at 5:51 p.m., CDT.

_______________________________________

Committee Chairperson

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Sponsors:


Updated: 12/14/2010 6:20 PM by Aisha N Hagen A Page 1

Subject: Audit Committee Chair Engagement Letter Authority



Background:HISTORY:

12/20/10 Board of Directors TABLED Next: 01/24/11

16.B.1

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Authority of Audit Committee Chair to Execute Certain Contracts

RESOLVED BY THE BOARD OF DIRECTORS OF THE COOPERATIVE, that the Chair of the Audit Committee is, authorized, as a duly authorized agent of the Cooperative, for and in the name and on behalf of the Cooperative, to execute any engagement letter(s) with internal and external auditors, consistent with and pursuant to terms of such engagements as approved by Board resolution.

16.B.1

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Sponsors:


Updated: 1/19/2011 9:35 AM by Renee Oelschleger B Page 1

Subject: Conservation Programs



Background:HISTORY:


18.B.1

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Conservation Programs

RESOLVED BY THE BOARD OF DIRECTORS OF THE COOPERATIVE, that theCooperative will continue to offer a cost-effective Energy Audit Program, Commercial Lighting Rebate Program, and HVAC Rebate Program; and

BE IT FURTHER RESOLVED that the Cooperative will ensure that these energy efficiency programs meet the cost-effectiveness standards established by the Public Utility Commission of Texas in Substantive Rule 25.181 (d); and

BE IT FURTHER RESOLVED, that the Acting Chief Executive Officer or his designee isauthorized to take such actions as needed to implement this resolution.

18.B.1

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Governance, Bylaws & Legal Committee

PO Box 1 Johnson City. TX 78636

Committee Meeting www.pec.coop

- Minutes- Call PEC Toll Free 1-888- 554-4732

Frida~December3,2010 10:00 AM PEC Headquarters Auditorium 201 South Avenue F


I. CaII to Order 10:00 AM Meeting was called to order at 10:15 AM on December 3,2010 at PEC Headquarters Auditorium, 201 South Avenue F, Johnson City, TX.

Attendee Name Title Status Arrived M~~~~",,· _~.'~"o_ "'""~~ ,~_ ~ ~ ,,~~, ~~~~«~-~,-<,-~"<~,~~"'~" -~"'-«<'" ,~"'" ,~« ~~,,' ~

Dr. Patrick Cox Committee Chairperson Present Ross Fischer Committee Member Present Larry Landaker Committee Member Present Jeanell Davis Assistant General Manager Present Luis Garcia Acting General Manager Present Toni ~~yes Community Relations Man?lger Present Trista Fugate Community Development Supervisor Present Pete Slover Special Counsel Present Lana Freudenber Administrative Assistant Present

II. Review and Approve Minutes

1. Monday, November 01, 2010

III. Member Comments No members commented.

IV. Open Session

A. Unfinished Business

1. Competitive Matters Policy

Pete Slover presented a draft policy for committee consideration. Committee indicated that the Directors will mark up proposed the policy so staff can bring a revised version to the next committee meeting.

2. Delegation of Authority Luis Garcia gave brief comments on the suggested amendments to the policy. Committee and staff discussed the proposed changes and instructed staff to prepare a resolution for Board consideration at the December Board Meeting. Larry Landaker moved, Ross Fischer seconded to send the proposed amendments for the Delegation of Authority to the Board of Directors meeting on December 20,2010.

3. Update on Community Connections Luncheons

Governance, Bylaws & Legal Committee Page 1 Revised 111012011

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Committee Meeting Minutes December 3,2010

Jeanell Davis gave a brief update on the cancellation of the events due to lack of participation. Trista Fugate presented possible options for next years events. Luis Garcia gave comments on his experience with the Community Connections events. Committee discussed and instructed to staff to continue with a plan and report back to committee when the plan is complete.

B. New Business

1. Use of Title Chief Executive Officer Larry Landaker moved, Ross Fischer seconded to send the presented resolution implementing the changes from "General Manager" to "Chief Executive Officer" to the Board at the December 20, 2010 Board of Directors meeting.

2. Updating Policies and Procedures

Pete Slover stated Legal staff will be reviewing and suggested changes to existing policies and procedures. Lana Freudenberg gave a brief update on the changes needed in the Director's Governance Manuals, committee instructed her to have updated materials ready for distribution at the December 20, 2010 Board Meeting.

3. Scope of Committees' Charters

Deferred to next meeting.

4. Ballot Language Dr. Cox described the need for this item to be prepared at the earliest time possible to present the changes as passed in the Bylaws.

5. 2011 Planning for Governance Committee Dr. Cox briefly discussed the policies that need to be reviewed and possibly amended by the Board during the upcoming year.

6. Legislative Update Dr. Cox stated he did contact Mike Williams with TEC to discuss upcoming legislature and requested staff follow up on this item in January.

V. Executive Session

A. Legal Break for Executive session at 12:03 Luis Garcia departed executive session at 12:06

1. Investigation Update


VI. Open Session Reconvene to Open Session at 12:08

LVII. Adjournment 12:10 adjournment

Governance, Bylaws &Legal Committee Page 2 Revised 111012011

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Committee Meeting Minutes December 3, 2010

VIII. Committee Signature

There being no further business to come before the Governance, Bylaws & Legal Committee, meeting was adjourned.

Governance, Bylaws & Legal Committee Page 3 Revised 111012011

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Sponsors:


Updated: 1/12/2011 9:05 AM by Renee Oelschleger Page 1

Subject: Amendment to Delegation of Authority/Gen. Counsel



Background:HISTORY:


21.B.1

Packet Pg. 359



Amendment to Delegation of Authority Regarding General Counsel

RESOLVED BY THE BOARD OF DIRECTORS OF THE COOPERATIVE, that the PEC Board Policy on Authority and Responsibilities (the "Delegation of Authority Policy"), initially adopted on September 15, 2008, and amended on November 17, 2008, November 16, 2009, March 15, 2010 and September 20, 2010 be further amended by making the following changes to items "b)" and "c)" in the section entitled "Authority Reserved to the Board of Directors", as follows (insertions underlined, deletions strike through):

b)Confirm the General Manager's appointment of Approve the appointment and employment terms, and periodically review the performance of the PEC General Counsel.

c)Consult with the General Counsel, independent of the General Manager. in a manner that recognizes that the General Counsel’s legal client is the Cooperative, as an entity. This reservation is not exclusive, and does not withhold from the General Manager the authority to separately consult with the General Counsel.

to read:

b) Approve the appointment and employment terms, and periodically review the performance of the PEC General Counsel.

c) Consult with the General Counsel in a manner that recognizes that the General Counsel’s legal client is the Cooperative, as an entity.

and;

BE IT FURTHER RESOLVED BY THE BOARD OF DIRECTORS OF THE COOPERATIVE, that in the section entitled "Delegation of Authority to the General Manager," the existing item "d)" is stricken and the subsequent item "e)" is relabeled as item "d)," as follows:

d) Appoint the PEC General Counsel, subject to Board Approval.

e) Consult with the General Counsel.

21.B.1

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and;

BE IT FURTHER RESOLVED, that the Acting General Manager Chief Executive Officeror his designee is authorized to take such actions as needed to implement this resolution.

21.B.1

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Sponsors:


Updated: 1/18/2011 7:51 PM by Aisha N Hagen Page 1

Subject: TEC 2011 Annual Membership Dues




• 2011 TEC Annual Dues Invoice (PDF)

22.B.1

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TEC 2011 Annual Membership Dues

RESOLVED BY THE BOARD OF THE DIRECTORS OF THE COOPERATIVE, that the Texas Electric Cooperatives (TEC) membership dues for 2011 in the amount of $127,809.28 are hereby approved.

22.B.1

Packet Pg. 363

RECEIVEDEll. Texas Electric ~~~~,~!:,~,~~~~ DEC 2 7 2010Office of the President and Chief Executive Officer

1122 Colorado Street, 24th Floor G.M. Ot- t ; '.,Austin, TX 78701 Telephone: (512) 486-6200 Fax: (512) 486-6206 www.texas-ec.org

December 17, 2010

Pedemales Electric Cooperative P.O. BOX 1 Johnson City, TX 78636

Enclosed you will find your membership dues invoice for 2011.

If you have any questions, please do not hesitate to call me at (512) 486-6203 or Texas Electric Cooperative's Chief Financial Officer, Elizabeth Montoya, at (512) 486-6231.

Thank you for your support and contributions to a unified electric cooperative program throughout the year.

Sincerely,

Mike Williams President/CEO

Enclosures: 2011 Membership Dues Invoice

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• Texas Electric Cooperatives P.O. Box 201338 Dallas, TX 75320-1338

December 17,2010

Pedernales Electric Cooperative P.O. BOX 1 Johnson City, TX 78636

Invoice No.: INVTEC02329

INVOICE

Membership Dues for 2011 :

Equal Payment $7,550.88

Meters Payment $51,550.85

Revenue less Cost of Power Payment $68,707.55

Total Membership Dues for 2011 $127,809.28

Please make check payable to: Texas Electric Cooperatives P.O. Box 201338 Dallas, Texas 75320-1338

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Documents

Regular Meeting · 1/24/2011 · Board of Directors PO Box 1 Johnson City, TX 78636 Regular Meeting ~ Agenda Call PEC Toll Free 1-888- 554-4732 Monday, January 24, …