January 19, 2016 Board Meeting Notice, Agenda and Supporting

Transcription

Board of Directors
Tuesday, January 19, 2016
PO Box 1
Johnson City, TX 78636
Regular Meeting
www.pec.coop
~ Agenda ~
Call PEC Toll Free
1-888- 554-4732
9:00 AM
PEC Headquarters Auditorium
Open Session of this Regular Meeting is held in the PEC Auditorium and will be video recorded
in accordance with Open Meetings Policy. Members may also watch this meeting by livestream from the PEC website at http://www.pec.coop/boardvideos
1.
Call to Order and Roll Call
9:00 AM Meeting called to order on January 19, 2016 at PEC Headquarters
Auditorium, 201 South Avenue F, Johnson City, TX.
The following agenda items may be considered in a different order than they appear.
2.
Adoption of Agenda
3.
Member Comments (3 minute limitation or as otherwise directed by Board)
4.
Minutes Approval
A.
5.
Matters From Directors
A.
Emily Pataki
1.
B.
(Resolution (ID # 3331)) Director Travel Expense Policy Amendments
Paul Graf
1.
6.
Thursday, December 17, 2015 Regular Meeting
(Resolution (ID # 3354)) Proposed Amendment to Election Policy and Procedures
Relating to Voter History Information
Matters from Legal Counsel
A.
(Resolution (ID # 3346)) 2016 Election Timeline Revisions - D Richards
B.
2016 Appointment of Qualifications and Elections Committee - D Richards
C. 2016 Election and Ballot Initiative Update - D Richards
D. (Resolution (ID # 3325)) Direct Outside General Counsel to Prepare 2016 Ballot
Item(s) - D Richards
7.
Chief Executive Officer
A.
CEO - Reports
Board of Directors
Page 1
Revised 1/15/2016
Regular Meeting
B.
8.
1.
Chief Executive Officer - 2015 Year in Review / 2016 Outlook
2.
Corporate Services Report (written report in materials)
3.
Operations Report (written report in materials)
4.
Engineering and Energy Innovations Report (written report in materials)
5.
Power Supply & Energy Services Report (written report in materials)
6.
Member Services Report (written report in materials)
7.
Information Technology Report (written report in materials)
January 19, 2016
CEO - Action Items/Other Items
1.
(Resolution (ID # 3315)) NRECA 2016 Annual Membership Dues - J Hewa
2.
Rate Plan and Member Feedback - I Sterzing
3.
(Resolution (ID # 3343)) Amendments to On-Bill Financing Loan Policy and
Underwriting Guidelines and Tariff Amendment - B Beavers
4.
(Resolution (ID # 3349)) Construction and Engineering Master Service
Agreements_Additional Contractors- B Hicks
Future Items for Board Consideration
A.
9.
Agenda
Board Meeting Planning Calendar - S Romero
Proposed Future Meetings (subject to final posting)
A.
February Regular Meeting - 9:00 am on Monday, February 22, 2016 at the PEC
Headquarters
B.
March Regular Meeting - 9:00 am on Monday, March 21, 2016 at the PEC
Headquarters
C. April Regular Meeting - 9:00 am on Monday, April 18, 2016 at the PEC Headquarters
10.
Executive Session
A.
B.
Legal Matters
1.
Update on Litigation and Related Legal Matters
2.
Matters in Which the Board Seeks the Advice of Its Attorney as Privileged
Communications in the Rendition of Professional Legal Services
Competitive Matters
1.
Board of Directors
Competitive Grants Update - P Muhoro
Page 2
Revised 1/15/2016
Regular Meeting
2.
C.
Power Supply Update - I Sterzing
Facilities and Real Estate Update and Review
Security Matters
1.
E.
January 19, 2016
Real Estate Matters
1.
D.
Agenda
Safety and Security Matters
Personnel Matters
1.
Personnel Matters Update
2.
Annual CEO Performance Evaluation - E Pataki
11.
Reconvene to Open Session
12.
Items from Executive Session
13.
Adjourn
Board of Directors
Page 3
Revised 1/15/2016
4.A
Board of Directors
Thursday, December 17, 2015
PO Box 1
Regular Meeting
www.pec.coop
~ Minutes ~
Call PEC Toll Free
1-888- 554-4732
9:00 AM
PEC Headquarters Auditorium
1.
Call to Order and Roll Call
9:00 AM Meeting called to order on December 17, 2015 at PEC Headquarters
Auditorium, 201 South Avenue F, Johnson City, TX.
Attendee Name
Cristi Clement
Emily Pataki
Kathryn Scanlon
Chris Perry
Paul Graf
Amy Lea SJ Akers
James Oakley
2.
Title
District 1 Director
District 2 Director
District 3 Director
District 4 Director
District 6 Director
District 7 Director
District 5 Director
Status
Present
Present
Present
Late
Present
Present
Present
Arrived
9:12 AM
9:12 AM
9:12 AM
12:14 PM
9:12 AM
9:12 AM
9:12 AM
Adoption of Agenda
The agenda was adopted as presented by consent.
3.
Member Comments (3 minute limitation or as otherwise directed by the Board)
The following members spoke on topics including but not limited to:
Mark Axford - elimination of convenience fees, bill credits for use of bank drafts, proposed
revision to Beat the Peak program, and smart meters for participating members.
Tom "Smitty" Smith - encouraged no vote on Clean Power Plan resolution, offered alternative
and distributed information the impact of climate change.
Lucy Stolzenberg - encouraged voting against the Clean Power Plan resolution.
Ernest Altgelt - request for data on how Clean Power Plan would increase rates, amicus brief,
the questioning of Director Perry, and director conflict of interests.
Matt Weldon - encouraged voting against the Clean Power Plan resolution.
Rick Sternberg - support for protecting the environment and elimination of coal plants, against
becoming involved in Clean Power Plan lawsuit.
Annie Borden - encouraged voting against the Clean Power Plan resolution.
Larry Landaker - encouraged rejection of the Clean Power Plan resolution and a study of the
numbers.
Board of Directors
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Packet Pg. 4
Minutes Acceptance: Minutes of Dec 17, 2015 9:00 AM (Minutes Approval)
Open Session of this Regular Meeting was held in the PEC Auditorium and was video recorded
in accordance with Open Meetings Policy. Members were able to watch this meeting by livestream from the PEC website at http://www.pec.coop/boardvideos
4.A
Regular Meeting
Minutes
December 17, 2015
Karen Hadden - discouraged involvement in Clean Power Plan lawsuit, support for renewables
power purchases.
5.
Announcements
A.
December 24 & 25, 2015 - PEC Offices Closed for Christmas Holiday
B.
January 1, 2016 - PEC Offices Closed for New Year's Holiday
Minutes Approval
A.
Friday, November 13, 2015 Regular Meeting
Following a recommendation from Director Paul Graf, the minutes as presented were approved.
RESULT:
MOVER:
SECONDER:
AYES:
ABSENT:
6.
ACCEPTED [UNANIMOUS]
Paul Graf, District 6 Director
Kathryn Scanlon, District 3 Director
Clement, Pataki, Scanlon, Graf, SJ Akers, Oakley
Chris Perry
Matters From Directors
A.
James Oakley
1. (Resolution (ID #3298)) 2016 NRECA/NRTC/CFC Annual Meetings Voting Delegates
President James Oakley and Director Kathy Scanlon stated that they may attend the NRECA
Annual Meeting. Since there was time to consider this item at a later date, President James
Oakley stated that this item would be placed on a future agenda for consideration.
B.
Kathy Scanlon
1.
Presentation on the Benefits to Texas of the Clean Power Plan - John Hall,
Environmental Defense Fun
Director Kathy Scanlon introduced Clean Energy Texas State Director John Hall and reviewed
his background in the industry. Mr. John Hall distributed and reviewed information included in
the Well Within Reach: How Texas Can Comply with and Benefit from the Clean Power Plan
presentation as attached (appendix 6.B.1.a.). Mr. Hall provided a background on the
Environmental Defense Fund, which is an environmental advocacy organization with an
emphasis on science, technology development and negotiations to resolve complicated
environmental issues in a cost effective manner, especially issues in the electricity sector. Mr.
Hall reviewed his organizations findings, along with the water, economic, and health benefits of
the Clean Power Plan. Mr. Hall stated that Texas was on track for compliance with the Clean
Power Plan. At 10:18 am President James Oakley announced a break and the meeting
reconvened at 10:38 am. President James Oakley recognized LCRA General Manager Phil
Wilson and TEC Senior VP of Government Relations and Legal Affairs Eric Craven who were in
the audience.
C.
Emily Pataki
Board of Directors
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4.
4.A
Regular Meeting
Minutes
December 17, 2015
2. (Resolution 2015-99) Authority to File Amicus Curiae Brief
Director Emily Pataki moved to approve the resolution as included in the Board package for
Authority to File Amicus Brief with No Direct Cost in Challenge of Clean Power Plan (CPP).
Director Paul Graf seconded the motion. CEO John Hewa stated that staff would make
available a North American Electric Reliability Corporation (NERC) report on reliability and
expected another NERC report by the first quarter of 2016. Mr. Robert Henneke Director for
Center for the American Future at the Texas Public Policy Foundation, a non-profit research
institute, reviewed his foundation's mission, and the ways other organizations were challenging
and supporting Clean Power Plan. Mr. Henneke offered representation services to the
Cooperative, at no cost, to assist in filing an amicus brief that would communicate the projected
impact of the CPP on the Cooperative and its members before the District of Columbia courts.
Mr. Henneke asked the Board to consider being their client and allowing them to draft a brief in
consultation with them.
Following a statement of opposition from Director Cristi Clement, Director Kathy Scanlon moved
to approve a substitute resolution "PEC's Oversight of EPA's Clean Power Plan" as attached
(appendix 6.C.2.a.) and Director Cristi Clement seconded. Director Chris Perry joined the
meeting at 12:14 pm. Following discussion and a point of order from Director Chris Perry,
Director Emily Pataki moved the following substitute resolution in place of the original resolution,
"Direct staff to produce an amicus brief for the limited purpose of educating the court and raising
awareness of the real effects of this Clean Power Plan on Pedernales Electric Cooperative, its
members and citizens alike." Director Amy Akers seconded the motion. In response to a
director inquiry, TEC Senior VP of Government Relations and Legal Affairs Eric Craven stated
that there was no way to communicate PEC's specific situation before the court without filing an
amicus brief. Director Paul Graf called the question and the Board voted 4 to 3 to end the
debate with Directors Clement, Scanlon and Perry opposed. The Board voted 4 to 3 in favor of
the substitute motion with Directors Clement, Scanlon and Perry opposed. Director Kathy
Scanlon withdrew her substitute motion.
President James Oakley provided an overview of the types of items to be discussed in
Executive Session and the reasons those items must be discussed in Executive Session. At
12:35 pm President James Oakley stated that the Board would go into Executive Session and
would return at approximately 3:00 pm to continue the Open Session.
Board of Directors
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1. Discussion and Presentation of PEC Impacts of Federal Clean Power Plan
Director Emily Pataki reviewed points from the ERCOT report, including power cost increases,
reliability concerns, and energy efficiencies costs. Director Emily Pataki commented on EPA
considerations, energy resources, the focus moving forward, ensuring a clean environment, and
the duty to provide low cost, safe and reliable electricity. CEO John Hewa, VP of Power Supply
and Energy Services Ingmar Sterzing, and VP of Legal Services Don Ballard reviewed the
Clean Power Plan PowerPoint presentation as attached (appendix 6.C.1.a.). Staff answered
questions regarding energy availability in a severe event. In closing CEO John Hewa stated that
the Cooperative should engage, identify needs going forward, fill in the unknowns about the
plan, and be prepared for any risks or opportunities from the plan.
4.A
Regular Meeting
Minutes
ADOPTED [4 TO 3]
Emily Pataki, District 2 Director
Amy Lea SJ Akers, District 7 Director
Emily Pataki, Paul Graf, Amy Lea SJ Akers, James Oakley
Cristi Clement, Kathryn Scanlon, Chris Perry
7.
Reconvene to Open Session at 2:20 pm
8.
Matters from Legal Counsel
A.
(Resolution 2015-108) Compliance and Qualifications Question of Director Chris
Perry to Affirm Directors Code of Conduct - Notice to Comply
Outside Counsel Don Richards reviewed his duties as a liaison with outside counsel and as a
monitor of director compliance with policies. Mr. Richards stated that he believed the lawsuit
had been dismissed as there had been no challenge of Director Perry's nonsuit. Mr. Richards
stated that at last week's meeting he asked Director Perry the unanswered discovery questions,
and that Director Chris Perry indicated he was in compliance with the conflict of interest. Mr.
Richards reported that during the time of the lawsuit Director Chris Perry had signed the Code
of Conduct form with a qualifying statement. When Mr. Richards raised the question of
resigning the Code of Conduct form, Director Perry stated that he would speak to his counsel
and get back with us. This form has not yet been received. Following discussion on the Code of
Conduct compliance, Outside General Counsel reviewed remedies the Board could take
including issuing a verbal reprimand, giving 30 days to come in compliance, or a taking a more
formal action to address his duty of obedience. Director Emily Pataki moved to instruct Director
Chris Perry that he has until the adjournment of the next scheduled meeting, January 12th to
sign an unabridged unqualified version of the Code of Conduct as we all have had to do as
sitting directors. Director Kathy Scanlon seconded the motion and the Board unanimously
approved. Later in the meeting, the Board acknowledged that an incorrect date was referenced
in the resolution. Director Emily Pataki moved to amend the date in the compliance resolution
to say January 11th which was the date of the scheduled meeting. Director Kathy Scanlon
seconded the motion to amend and the Board unanimously approved the amendment.
RESULT:
MOVER:
SECONDER:
AYES:
ABSENT:
ADOPTED [UNANIMOUS]
Chris Perry
B. Announcement of 2016 Election Timeline - D Richards
Outside General Counsel Don Richards reviewed the 2016 Election Timeline as highlighted and
attached (appendix 8.B.1.). In response to director inquiries, Mr. Richards reviewed the role,
duties, and meeting date(s) of the Qualifications and Election Committee.
9.
Matters from Directors (continued)
A.
Board of Directors
(Resolution 2015-107) 2016 NRECA/NRTC/CFC Annual Meetings Voting Delegates
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Packet Pg. 7
RESULT:
MOVER:
SECONDER:
AYES:
NAYS:
December 17, 2015
4.A
Regular Meeting
Minutes
December 17, 2015
President James Oakley stated that due to a deadline this item must be addressed prior to the
next meeting in January. Following discussion, the Board voted to appoint Kathy Scanlon as
voting delegate and James Oakley as alternate delegate as more fully stated in the resolution.
RESULT:
MOVER:
SECONDER:
AYES:
ABSENT:
A.
CEO - Reports
1. Chief Executive Officer Update - J Hewa
CEO John Hewa reviewed the Chief Executive Officer Update PowerPoint presentation as
attached (appendix 8.A.1.a.).
2. Financial Services Report - T Golden
CFO Tracy Golden reviewed the Monthly Financials Report as included in the Board package
and answered questions on net margins and cost saving in interest.
3. Corporate Services Report (written report in materials)
The written materials for Corporate Services Report were included in the Board package.
4. Operations Report (written report in materials)
The written materials for Operations Report were included in the Board package.
5. Engineering and Energy Innovations Report (written report in materials)
The written materials for Engineering and Energy Innovations Report were included in the Board
package.
6. Member Services Report (written report in materials)
The written materials for Member Services Report were included in the Board package.
7. Communications & Business Services (written report in materials)
The written materials for Communications and Business Services Report were included in the
Board package.
B.
CEO - Action Items/Other Items
1. (Resolution (ID # 3278)) 2016 Operating Budget & Capital Improvement Plan
CFO Tracy Golden stated that the 2016 Budget PowerPoint presentation and resolution were
included the package. Following Director Kathy Scanlon's motion to approve, the Board asked
Board of Directors
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10.
ADOPTED [UNANIMOUS]
Cristi Clement, District 1 Director
Chris Perry
4.A
Regular Meeting
Minutes
December 17, 2015
to continue discussions in Executive Session. Director Amy Akers moved to table this item until
following Executive Session and Director Emily Pataki seconded. President James Oakley
stated that this item would be considered after Executive Session.
(Resolution 2015-102) 2016 Key Performance Indicator Plan and Methodology - J
Hewa / M Racis
CEO John Hewa and VP of Communications and Business Services Michael Racis reviewed
the 2016 Key Performance Indicator (KPI) Plan Recommendations PowerPoint Presentation
and the 2016 Key Performance Indicator Plan and Methodology as attached (appendix
10.B.2.a. & 10.B 2.b).
RESULT:
MOVER:
SECONDER:
AYES:
ABSENT:
ADOPTED [UNANIMOUS]
Chris Perry
3.
(Resolution 2015-103) 2016-2020 Vegetation Management Master Service
Agreements for Distribution and Transmission Vegetation Maintenance - B Hicks
VP of Engineering and Energy Innovations Brad Hicks reported on the master service
agreements expiring and the resolution seeking approval of the proposed contracts as included
in the Board package.
RESULT:
MOVER:
SECONDER:
AYES:
ABSENT:
ADOPTED [UNANIMOUS]
Chris Perry
4.
(Resolution 2015-104) Authorization For Regulatory Action with Public Utility
Commission of Texas Regarding Service Area Encroachments - W McKee / A Hagen
Special Counsel Aisha Hagen and VP of Operations Wayne McKee reviewed the Authorization
for Regulatory Action with Public Utility Commission of Texas Regarding Service Area
Encroachments PowerPoint presentation as attached (appendix 10.B.4.a.) and the resolution as
included in the package.
RESULT:
MOVER:
SECONDER:
AYES:
ABSENT:
ADOPTED [UNANIMOUS]
Chris Perry
5.
(Resolution 2015-105) Amendments to On-Bill Financing Loan Policy and
Underwriting Guidelines - B Beavers
Energy Services Manager Blake Beavers reviewed the Amendments to On-Bill Financing Loan
Policy and Underwriting Guidelines PowerPoint presentation as attached (appendix 10.B.6.a.).
Board of Directors
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2.
4.A
Regular Meeting
Minutes
RESULT:
MOVER:
SECONDER:
AYES:
ABSENT:
11.
December 17, 2015
ADOPTED [UNANIMOUS]
Chris Perry
Future Items for Board Consideration
12.
Proposed Future Meetings (subject to final posting)
A.
January Special Meeting - 9:00 am on Monday, January 11, 2016 at the PEC
Headquarters
B.
January Regular Meeting - 9:00 am on Tuesday, January 19, 2016 at the PEC
Headquarters
After announcing tentative dates for a Special Meeting on Monday, February 8, 2016 and a
Regular Meeting on Monday, February 22, 2016, President James Oakley stated that he wanted
to work with staff for a single monthly meeting if possible. Director Cristi Clement shared that
she was invited to speak on a panel at the NRECA New Director Orientation and would be
attending at no expense to the Cooperative. President James Oakley provided an overview of
the types of items to be discussed in Executive Session and the reasons those items must be
discussed in Executive Session. At 3:38 pm President James Oakley stated that the Board
would go into Executive Session.
13.
Executive Session
A.
B.
C.
Security Matters
1.
Safety and Security Matters
2.
Continuing Discussion on Cyber Security Planning and Preparedness Measures - L
Parnell/T Shaheed
Legal Matters
1.
Update on Litigation and Related Legal Matters
2.
Matters in Which the Board Seeks the Advice of Its Attorney as Privileged
Communications in the Rendition of Professional Legal Services
3.
Ethics and Compliance Report Update
Competitive Matters
Board of Directors
Page 7
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Packet Pg. 10
A. Board Meeting Planning Calendar (written report in materials)
The Board Meeting Planning Calendar was included in the Board package.
4.A
Regular Meeting
1.
(Resolution (ID # 3304)) Distribution Poles – Blanket Purchasing Agreement - B
Hicks
Real Estate Matters
1.
F.
Continuation of Discussion Regarding 2016 Operating Budget, Capital Improvement
Plan (CIP), and Work Plan Including Items Concerning Competitive Matters,
Personnel, Contracts and Real Estate (as needed) - T Golden
Contract Matters
1.
E.
December 17, 2015
Facilities and Real Estate Update and Review
Personnel Matters
1.
Personnel Matters Update
2.
Discussion of Annual CEO Performance Evaluation Process - E Pataki
14.
Reconvene to Open Session at 4:35 pm
15.
Items from Executive Session
A.
(Resolution 2015-106) Distribution Poles - Blanket Purchasing Agreement - B Hicks
RESULT:
MOVER:
SECONDER:
AYES:
ABSENT:
ADOPTED [UNANIMOUS]
Cristi Clement, Paul Graf, Amy Lea SJ Akers, James Oakley
Emily Pataki, Kathryn Scanlon, Chris Perry
B.
(Resolution 2015-101) 2016 Operating Budget & Capital Improvement Plan - T
Golden
At 4:37 pm Director Emily Pataki rejoined the meeting by phone.
RESULT:
MOVER:
SECONDER:
AYES:
ABSENT:
16.
ADOPTED [UNANIMOUS]
Clement, Pataki, Graf, SJ Akers, Oakley
Kathryn Scanlon, Chris Perry
Adjourn
There being no further business to come before the Board of Directors, meeting was adjourned
at 4:39 pm.
Board of Directors
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D.
Minutes
4.A
Regular Meeting
Minutes
December 17, 2015
____________________________________
Paul Graf, Secretary
APPROVED:
_______________________________________
James Oakley, President
Board of Directors
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6.B.1.a
4.A
Attachment: Well Within Reach How
Minutes
Texas
Acceptance:
Can Comply
Minutes
with and
of Dec
Benefit
17, from
2015 the
9:00Clean
AM (Minutes
Power Plan
Approval)
2015-12-17 (3328 : Presentation on the
12/16/2015 CONTENTS
PRESENTATION: FINDINGS AND CONCLUSIONS
APPENDICES: DELVING DEEPER
./ BENEFITS OF CPP COMPLIANCE
./ SCENARIOS USED FOR THIS ANALYSIS
./ MARKET TRENDS
./ CLEAN ENERGY MEASURES BEYOND
GENERATION
1
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10
r
6.B.1.a
4.A
••
Minutes
Texas
Acceptance:
Can Comply
Minutes
with and
of Dec
Benefit
17, from
2015 the
9:00Clean
AM (Minutes
Power Plan
Approval)
12/16/2015
Clean Power Plan Overview
NATIONAL GOAL:
~
Reduce C02emissions from existing power plants 32 percent below
2005 levels by 2030.
TEXAS GOAL:
~
The Clean Power Plan enables Texas the flexibility to pursue compliance
with either a rate-based or mass-based target that were crafted to be
equivalent. This EDF analysis focuses on rate-based targets due to data
availability, but we support either approach.
• 2030 Target: Reduce emissions intensity of existing power
sources 33 percent from a 2012 baseline rate of 1,566 Ibs/MWh
to an average of 1,042 Ibs/MWh by 2030.
• 2022-2029 Interim Target: Average emissions rate of 1,188
Ibs/MWh.
How Does Texas Compare to Other States?
300 -50%
•
-45%
-40%
-35%
-30%
-25%
-20%
-15%
-10%
-5%
0%
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11
6.B.1.a
4.A
Minutes
Acceptance:
Minutes
of Dec
17, from
2015 the
9:00Clean
AM (Minutes
Approval)
Texas
Can Comply
with and
Benefit
Power Plan
12/16/2015 Texas Clean Energy Market Trends
,/ MARKETS: Deregulation created the opportunity for more retail electricity
providers to compete with one another within ERCOT, forcing inefficient
resources to give way to more cost-effective options.
,/ INFRASTRUCTURE: The construction of the CREZ lines has facilitated the
growth of renewables, especially wind.
,/ TECHNOLOGY:
• Prices for renewable energy and natural gas have declined significantly
over the past decade to become the state's most competitive fuels.
• 80 percent ofTexas coal plants will be more than 40 years-old by 2030,
meaning dirtier, less efficient plants that will be forced to retire.
BOTTOM LINE: Effective policies, encouraged by the Clean Power Plan , can
accelerate this trend by supporting growth of low-carbon technologies, while
ensuring reliable power and keeping electricity affordable.
Texas is Most Resource-Rich State for Clean Energy
UNMATCHED RENEWABLE ENERGY
POTENTIAL
,/ Texas has more than twice the wind potential and
three times the solar potential of any other state.
,/ According to SNL Financial (June, 2015), wind
capacity in Texas in 2020 should exceed 30 GW,
about double 2015 capacity.
,/ According to Bloomberg New Energy Finance
(June, 2015), U.S. wind and solar capacity will
grow 32 percent and 271 percent from 2020 to
2030, respectively.
• As the state that has the most potential for
both of these resources, Texas should
comprise a significant proportion of this
growth .
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12
6.B.1.a
4.A
Minutes
Acceptance:
Minutes
of Dec
17, from
2015 the
9:00Clean
AM (Minutes
Approval)
Texas
Can Comply
with and
Benefit
Power Plan
12/16/2015 Texas is Most Resource-Rich State for Clean Energy
ENERGY EFFICIENCY
./ Texas has significant potential to deploy more energy efficiency and energy management programs, including demand response. CLEANER FOSSIL ALTERNATIVES
./ Texas has more natural gas reserves than any other state and currently produces 29 percent of the nation's natural gas . ./ Texas has more Combined Heat and Power (CHP) potential than any other state, in large part related to its refining and petrochemical sectors. Methodology
KEY INPUTS
./ The ERCOT region is the primary focus of our study, and we rely on ERCOT projections for three of our
four scenarios (below). Also, we focus on the rate-based CPP target due to data availability.
./ We use the MJ Bradley and Associates (MJB&A) ·CPP Compliance Tool - Version 2.0."
This tool is industry-funded and yields more conservative results (i.e. more difficult to comply with
the CPP) than similar models, including the PLEXOS model ERCOT has used in the past.
SCENARIOS & DATA
./ ERCOT Baseline: Uses 2020 and 2029 generation mix assumptions from ERCOT's "Current Trends"
scenario for its December 2014 report entitled Impacts of Environmental Regulations in the ERCOT
Region.
./ EDF Current Trends: Adjusts the ERCOT Baseline scenario based on forecasts ERCOT has made in
other publications over the past year for projected renewables and natural gas generation mix
percentages, as well as current energy efficiency activities occurring in ERCOT.
./ CPP Compliance Scenario: An example of a track Texas might take to comfortably achieve CPP
compliance. EDF does not necessarily recommend this path relative to others; rather, it is an illustrative
scenario.
,/ Beyond Compliance: An example of a track through which Texas could go well beyond CPP compliance
in a manner that is both comfortable for the state and maximizes economic, health, and water benefits.
4
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6.B.1.a
4.A
Minutes
Texas
Acceptance:
Can Comply
Minutes
with and
of Dec
Benefit
17, from
2015 the
9:00Clean
AM (Minutes
Power Plan
Approval)
12/16/2015 Clean Power Plan Compliance: Texas 88% of the Way There
1600
"
2012 Tex• • CPP b • • eIlM: 1,500 Ib./MWh i 1200
~
g
..
?:
c:
!!
.5
c:
•0
------- ~-------2030
Tex•• CPP la"Vet:
1,042 Ib./MWh
800
'i
1.108 IbaIMWh
11K to CPP goal
E
••
,.II
400
~
o
ERCOT no·reg baseline
EDF·Te)(as current trends
Ib IMWh
Flexibility is Our Friend
./ Texas may develop a compliance
plan consistent with ERGOT's
competitive market structure .
./ Texas may harness its abundant
natural gas, wind, solar, and energy
efficiency potential to export power
and/or sell carbon allowances or
emission reduction credits (ERG) to
states with a more difficult time
complying with the GPP.
• Texas can sell carbon
allowances or ERGs to other
states even if it does not form
a joint target with another
state.
5
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14
6.B.1.a
4.A
Minutes
Acceptance:
Minutes
of Dec
17, from
2015 the
9:00Clean
AM (Minutes
Approval)
Texas
Can Comply
with and
Benefit
Power Plan
12/16/2015 Compliance and Beyond
2030 targ l
1600
~====================~--.~~====================~
2012 rex.. CPP baseline: 1,500 Iba/MWh 2030 rexaa CPP baaellne: 1200
1,042 Iba/MWh •
800
§
=
E
1,100 IbeIMWh
1ft to CPP geNII
1/
:I
)(
400
~
o ~---------------EDF-Texas currenl trends 2029
CPP com liance scenario 2029
Maximizing Benefits by Going Beyond Compliance
Table 3 - CPP Compliance and Beyond Compliance
--------------~
Implementation of Volt/VAR
Optimization (WO) Measures
Yes
Increase Demand Response
(DR) Capacity from Current
2,500 MW Level to 6,350 MW
Yes
6
Packet Pg. 18
15
6.B.1.a
4.A
Minutes
Texas
Acceptance:
Can Comply
Minutes
with and
of Dec
Benefit
17, from
2015 the
9:00Clean
AM (Minutes
Power Plan
Approval)
12/16/2015 Clean Power Plan Benefits: Water
1,400,000 . - - - - - - - - - - - - - - - - - - - - - - ,
2010 weter dem."d
TWDB water demand
projections
EReOT no-reg BAU +current
rtliabiity margin
EDF·Taxes current trends +
current reliability margin
EDF beyond compbance +
current reliability margin
Clean Power Plan Benefits: Economy and Health
./ Economy benefits in the form of job and
revenue growth
• The Political Economy Research
Institute and the Center for
American Progress found the solar
industry creates nearly twice as
many jobs as coal and three times
as many as natural gas .
./ Health benefits from cleaner air
• A study evaluating a carbon
reduction strategy similar to the
CPP shows the plan would save
approximately 2300 lives and
prevent 790 hospitalizations and
140 heart attacks in Texas alone
between 2020 and 2030.
7
Packet Pg. 19
16
6.B.1.a
4.A
Minutes
Acceptance:
Minutes
of Dec
17, from
2015 the
9:00Clean
AM (Minutes
Approval)
Texas
Can Comply
with and
Benefit
Power Plan
12/16/2015 Clean Power Plan Compliance
Recommendations
1) Develop a state plan rather than allow a
federal plan.
2) Use the plan to grow the state's economy.
3) Use market-based approaches.
4) Maximize clean energy resources.
5) Fully implement Texas PACE finance
programs.
6) Develop a state plan with mid-course review
option.
7) Adjust future state water plans to reflect a less
water-intensive power sector.
Additional Standards Affecting the Power Sector
• Mercury and Air Toxic Standards
• The Cross-State Air Pollution Rule
• Regional Haze Program
• New health-based ozone standards
BOTTOM LINE: Texas should implement a cost-effective, multi-pollutant
Clean Power Plan compliance strategy which would enable the state to
comply with other environmental regulations more easily.
8
Packet Pg. 20
17
APPENDICES: DELVING DEEPER Attachment: Well Within Reach How
Minutes
Texas
Acceptance:
Can Comply
Minutes
with and
of Dec
Benefit
17, from
2015 the
9:00Clean
AM (Minutes
Power Plan
Approval)
6.B.1.a
4.A
12/16/2015 9
Packet Pg. 21
18
6.B.1.a
4.A
Minutes
Texas
Acceptance:
Can Comply
Minutes
with and
of Dec
Benefit
17, from
2015 the
9:00Clean
AM (Minutes
Power Plan
Approval)
12/16/2015 1) Benefits of CPP Compliance
Impact of CPP and Texas' Trends Toward Clean
Power on Electricity-Related Water Consumption
v' 2030 annual avoided water
consumption of 456,000
acre-feet, relative to the TWDS projected 2030 level, under ERCOT's "Current
Trends" scenario, which assumes no CSAPR,
Regional Haze, or Clean
Power Plan regulations.
Projected water demand for electricity
m1l8 v. [ Reo l 8~U ,,-Wf
-___
I TWD5 _OInwId
.....
. BICOT m~ BNJ
.....
.....
t c:;rr l'!"ll
EDf·.... MMl'tndl t
......
' EJf blyorld ~ t
v' 2030 annual avoided water
",.arJos
'...... f ,....
iI ","
I ..."
1
.",..
usage will reach upwards of
500,000 acre-feet under a
CPP compliance scenario.
10
Packet Pg. 22
19
6.B.1.a
4.A
Minutes
Texas
Acceptance:
Can Comply
Minutes
with and
of Dec
Benefit
17, from
2015 the
9:00Clean
AM (Minutes
Power Plan
Approval)
12/16/2015 Impact of CPP and Texas' Trends Toward Clean Power on Electricity-Related Water Consumption BOTTOM LINE: Increased utilization of clean energy resources
consistent with the goals of the CPP may eliminate the annual need
for 1.1 million additional acre-feet of water the TWB has projected
for the power sector for 2060. This amount of water is equivalent to
Lake Travis at full capacity, or almost ten-times the amount of water
in Lake Houston.
Health Benefits of CPP Compliance
By lessening air pollution , the Clean
Power Plan will save lives, make
Texans healthier, and lower associated
health costs .
./ A study evaluating a carbon
reduction strategy similar to the CPP
shows the plan would save
approximately 2300 lives and
prevent 790 hospitalizations and 140
heart attacks in Texas alone between
2020 and 2030.
Power sources that emit more carbon
generally emit more of other pollutants
as well. So reducing the power sector's
carbon pollution has the added benefit
of reducing other harmful pollutants at
the same time .
11
Packet Pg. 23
20
6.B.1.a
4.A
Minutes
Texas
Acceptance:
Can Comply
Minutes
with and
of Dec
Benefit
17, from
2015 the
9:00Clean
AM (Minutes
Power Plan
Approval)
12/16/2015 Economic Benefits of CPP Compliance
INCREASED JOBS:
v' The solar Industry creates nearly twice as many jobs as coal and three times as many as natural gas. In 2014,
the Solar Foundation found there are more solar jobs in Texas than there are ranchers, and Texas was listed
as one of the top 10 states for solar jobs.
v' Texas leads the country with over 17,000 wind industry jobs. In addition , for every 100,000 houses that are
retrofitted to use less energy, 10,000 local jobs are created.
INCREASED REVENUES :
v' Texas may harness its abundant natural gas, wind, solar, and energy efficiency potential to export power
and/or sell carbon allowances or ERCs to states with a more difficult time complying with the CPP.
• Texas can sell carbon allowances or ERCs to other states even if it does not form a joint target with
another state.
v' The more the state steps up its energy efficiency efforts, the more low-income communities benefit from lower
prices.
v' The CPP is expected to increase the utilization of natural gas on a national basis, so states such as Texas with
Significant natural gas reserves stand to benefit.
AUSTIN'S EXPERIENCE:
v'
$2.5 billion In added GOP and 20,000 added jobs due to its cleantech sector, which is expected to grow at
11 percent annually by 2020, almost twice the national growth rate.
Benefits to Texas of Exceeding CPP Compliance
Texas has the resources to exceed CPP compliance in
a comfortable manner.
./ ERCOT projects Texas wind power will reach 23.4 GW in 2017.
According to SNL Financial, wind capacity in Texas in 2020 should
exceed 30 GW, about double 2015 capacity.
./ According to Bloomberg New Energy Finance, U.S. wind and solar
capacity will grow 32 percent and 271 percent from 2020 to 2030,
respectively.
As the state that has the most potential for both of these
resources, Texas should comprise a significant proportion of
this growth.
12
Packet Pg. 24
21
6.B.1.a
4.A
Minutes
Texas
Acceptance:
Can Comply
Minutes
with and
of Dec
Benefit
17, from
2015 the
9:00Clean
AM (Minutes
Power Plan
Approval)
12/16/2015 Benefits to Texas of Exceeding CPP Compliance
Texas could benefit economically from exceeding its CPP target as follows: ../ Increase revenues stemming from : (1) sales of carbon allowances or
ERCs to EGUs in other states, or (2) the export of clean power to
other states.
• Note: Texas can sell carbon allowances or ERCs to other states
even if it does not form a joint target with another state .
../ The mo·re the state steps up its energy efficiency efforts, the more
low-income communities benefit from lower prices.
2) Scenarios Used for This Analysis
13
Packet Pg. 25
22
6.B.1.a
4.A
Minutes
Acceptance:
Minutes
of Dec
17, from
2015 the
9:00Clean
AM (Minutes
Approval)
Texas
Can Comply
with and
Benefit
Power Plan
12/16/2015 ERCOT Baseline - Assuming No ENV Regulations
Table 1 -ERCOT's 2012 Generation Mix vs. BAU Generation Mix Forecasts for 2020 and 2029
ERCOT2012
ERCOTNoReB Baseline
2020
EDF - Texas
Current Trends
2020
ERCOTNoReB Baseline
2029
EDF - Texas
Current Trends
2029
Natural Gas (%)
45
44
51
4S
51
Coal (%)
34
32
21
29
19
Renewables (%)
9
12
17
17
21
Nuclear (%)
12
10
10
9
9
Energy Efficiency
Savings (% of Load)
NA
1
1
1
1.4
The "ERCOT No-Reg Baseline" scenario (highlighted in orange in Table 1) uses
2020 and 2029 generation mix assumptions from ERCOT's "Current Trends"
scenario from its December 2014 report entitled Impacts of Environmental
Regulations in the ERGOT Region.
EDF Current Trends Scenario
Table 1 -ERCOT's 2012 Generation Mix vs. BAU Generation Mix Forecasts for 2020 and 2029
ERCOT 2012
ERCOT No-Reg
Baseline 2020
Natural Gas (%)
45
44
Coal (%)
34
32
Renewables (%)
9
12
Nuclear (%)
12
10
Energy Efficiency
Savings (% of Load)
NA
The "EDF Current Trends" scenario (highlighted in green in Table 1 ) adjusts the
"ERCOT No-Reg Baseline" scenario based on forecasts ERCOT has made over
the past year for projected renewables and natural gas generation mix
percentages, as well as current energy efficiency activities occurring in ERGOT.
14
Packet Pg. 26
23
6.B.1.a
4.A
Minutes
Texas
Acceptance:
Can Comply
Minutes
with and
of Dec
Benefit
17, from
2015 the
9:00Clean
AM (Minutes
Power Plan
Approval)
12/16/2015 Progress to CPP Compliance Under Current Trends
Table 2 - Progress to CPP Compliance Under Current Trends
ERCOT No-Reg
Baseline 2029
2022 Emissions Intensity, Assuming Linear Progress from
2020 to 2029 (lbs/MWh)
1,419
2030 Emissions Intensity (lbs/MWh)
1,315
47
% to Achieving EPA's 2030 Emissions Target, 1,042 Ibs/MWh
2022-2029 Emissions Intensity, Assuming Linear Progress
from 2020 to 2029
1,374
% to Achieving CPP 2022-2029 Interim Target, 1,188
51
Ibs/MWh, Assuming Linear Progress from 2020 to 2029
EDF Current Trends CPP Compliance Analysis - 2022-2029
1600
2012 Texas CPP baseline: 1.seD Ibs/ MWh
.
z
~
~
!
1200
- ---------------------------
------
2022-2029
Texes CPP target:
1,188 Ibe/MWh
~
c
•
~.,
g
BOO
1.1U lba,lMWh
107% to CPP geNII
-=
E
•
=
.
400
~
o
ERCOT no- reg baseline
EDF-Texas current t rends
IWIt
15
Packet Pg. 27
24
6.B.1.a
4.A
Minutes
Acceptance:
Minutes
of Dec
17, from
2015 the
9:00Clean
AM (Minutes
Approval)
Texas
Can Comply
with and
Benefit
Power Plan
12/16/2015 CPP Compliance Scenario
Table 3 - CPP Compliance and Beyond Compliance
f----------..,....,
--------i
Implementation of Volt/VAR
Optimization (WO) Measures
Yes
Increase Demand Response
(DR) Capacity from Current
2,500 MW Level to 6,350 MW
Yes
The "CPP Compliance" scenario (highlighted in blue in Table 3) is an example of a
track Texas might take to comfortably achieve CPP compliance, especially if the state
takes steps to increase energy efficiency outcomes.
3) Market Trends
16
Packet Pg. 28
25
.
6.B.1.a
4.A
12/16/2015 Minutes
Acceptance:
Minutes
of Dec
17, from
2015 the
9:00Clean
AM (Minutes
Approval)
Texas
Can Comply
with and
Benefit
Power Plan
,
Texas generation mix since deregulation: trending cleaner
9% ,--------------------------------, 8%
7% .._...................................... _..............................................._.
6% ....................
~
5% ....................
~
i
3% .._......._......................_............................. _......................_......................_...
Coe137%
• Natural gas 51 %
• Nucloar9%
Coal 35%
• Natural gal 47%
• Nuclear 9%
1% ....._ _ _- • Sclar PV/lhermal 0% • Wind 1% . 00her2%
O% ~------------------------------~
2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013
• Solar PV/lharmal 0%
• Wind 8%
• Other 1%
./ From 2002 , the year Texas' competitive retail market was implemented , to 2013, fossil fuels'
(coal and gas) proportion of the state's electricity generation mix shrunk from 88 percent to
82 percent.
./ Meanwhile , wind's share grew from 1 percent to 8 percent.
./ While the percentage of natural gas generation generally has remained steady in the range of 45 percent to 51 percent during the 1990-2013 period , the percentage of coal generation declined from almost 45 percent to 35 percent over the same period . Texas Electricity Price Trends
E Re OT 2 0 0 5- 2 01 4
$90 ,----------------------------------------------------------------,
$80
$70
$60
~
~
$50
$40
$30
$20
$10
-
Rees.l·time market price6
Unear (real-time market prices)
$0
2005
2006
2007
2008
2009
2010
2011
2012
2013
2014
:)ol1rce: Poto m rtc Economics
./ Natural gas prices were nearly halved during 2008-2014 .
./ T his price reduction has led to reduced wholesale electric prices in ERCOT and enabled
generation to compete more effectively against coal generation.
17
Packet Pg. 29
26
6.B.1.a
4.A
Minutes
Texas
Acceptance:
Can Comply
Minutes
with and
of Dec
Benefit
17, from
2015 the
9:00Clean
AM (Minutes
Power Plan
Approval)
12/16/2015 RE Price Trends - Recent Past
Wind and solar price curves
2009-2014
$250
$200
$1119
z;
~
0
U
' ~"rPe
•••• 'c."
$100
S101
$92
$50
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,
$95
LCOE
S48
$394
SOLAR PV LCOE
".
" ~e
-. it,.
......
$350
S95
--
$98
-
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$400
-" ••••••
las. C1ec:
• t.:~
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.
z;
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ii
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0
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............
$45
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$300
~
~~
$32\
70
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'
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•••••
$149
$101
••••
$8&
S9~
$72
$50
-
LCOE
LCOErange
$0
2009
2010
2011
2012
2013
2014
2010
2009
SoUra>' II"p.:II.I\,\\ ".3 orgl'iI""lder,ulllfil",l ...ou"""I",,'li"'I'Io2IJ{''''''Io20''~20FJ'''g)'\2(I.'\201'
2011
2012
2013
2014
lon~8, O pdri'~~rl,).,onI(>XI:"""""'"._"n'
I
"".aro"b"lIzcd-cOSl·<nergy·anal),ls·viIO
Fossil Fuel vs. RE Price Trends - Future
U.s. LCOE forecast*
201 5-2040
$120
~o
r-----------------------------------------------------------~
-
Utility PV (21 % capacity factor)
-
Coal
Natu ral gas (CCGT)
-
Onshore w ind (45% capacity factor)
L-__________________________________________________________
2015
Sourcl;': Oloombcr((
2020
I\e\",
2025
l:ner"8)1 fln.Ull . "lOJ5 l\c\\ Encfg) Out look
2000
2035
~
2040
America" June 2015. 'I.cOllls nn acron rn rnr .. Ii~\'CIl1.cd co 101 cnf'rg)-" IlerC'. II Is x-prcs....ed In 2015 nominal doUnTli rnol ~ dIU'iIPd for Inflation). Recent prices in Texas: Austin Energy is reported to have recently received offers for
solar power purchase agreement (PPA) at 4 cents/KWh . less than half the 10
cents/KWh BNEF estimates as the average in the United States,
18
Packet Pg. 30
27
6.B.1.a
4.A
Minutes
Acceptance:
Minutes
of Dec
17, from
2015 the
9:00Clean
AM (Minutes
Approval)
Texas
Can Comply
with and
Benefit
Power Plan
12/16/2015 New Technologies Will Facilitate CPP Compliance
LITHIUM-ION EV BATTERY EXPERIENCE CURVE
COMPARED WITH SOLAR PV EXPERIENCE CURVE
Bloomberg
"'w ••• ~ .. ~ . . ..
Li-ion EV battery
p.ock
100
1.000
10.000
100.000
1.000.000 10.000.000
Cumulative pmduction (MW. MWh)
Michael Llobl'"OlCh , New York 1. April 2015
(fI)MllObrolc.h
IJBNEFSurnrnii
13
Storage is the most promising opportunity:
,/ The market for storage for the purposes of integrating solar and wind resources is
estimated to grow 10,000 percent from about $30 million to approximately $3 billion over
the coming decade.
,/ Similar to solar PV costs, BNEF has documented the cost "experience curves" of Li-Ion
technologies to demonstrate the rapid decline in cost of this battery technology. Other
battery and storage technologies are experiencing similar rapid declines in cost.
4) Clean Energy Measures Beyond Generation
19
Packet Pg. 31
28
6.B.1.a
4.A
Minutes
Texas
Acceptance:
Can Comply
Minutes
with and
of Dec
Benefit
17, from
2015 the
9:00Clean
AM (Minutes
Power Plan
Approval)
12/16/2015 Energy Efficiency
2013 EE Rate in ERCOT: 0.21 percent.
.,/ This rate is far lower than Itron's 2008 assessment that 6.8 percent energy savings
were feasible over ten years, or ACEEE's 2007 conclusion that 11 percent was
achievable over fifteen years .
.,/ Austin Energy and CPS Energy of San Antonio, the state's two largest municipaliy
owned utilities within ERCOT, have already demonstrated how energy efficiency
programs lead to cost savings and may be implemented cost-effectively in Texas,
serving as a model for other parts of the state.
•
Energy Efficiency
Texas-specific studies may understate actual EE savings potential.
.,/ McKinsey (2009): 23 percent EE possible by 2020 relying
on measures that pay for themselves in a relatively short
period of time .
.,/ National Academy of Sciences (2010): 25-30 percent
savings feasible for the building sector by 2030-35 at a
cost of 2.7 cents per KWh, and 14-22 percent in the
industrial sector by 2020.
20
Packet Pg. 32
29
6.B.1.a
4.A
Minutes
Acceptance:
Minutes
of Dec
17, from
2015 the
9:00Clean
AM (Minutes
Approval)
Texas
Can Comply
with and
Benefit
Power Plan
12/16/2015 Demand Response
ERCOT DR Capacity:
./ 2,500 GW, or about 4 percent of peak demand. An additional 1 ,400 MW of demand
response that is active in ERCOT but not subject to its deployment.
./ Potential DR capacity ifTexas implements DR programs CPS Energy has
implemented: 6,350 MW, or 9 percent of peak demand (Brattle, 2014).
DR Grid Impact:
./ ACEEE estimates that a 13.5 percent peak load reduction in Texas is achievable
from DR. FERC's national estimate is 15 to 21 percent.
./ In 2011 , demand response prevented potential blackouts within ERCOT due to hot
weather, and again during the 2014 polar vortex due to power plant malfunctions.
DR Emissions Impact:
./ Up to 2 percent emissions savings (Navigant, 2014):
• 1 percent from peak load reductions.
• 1 percent from renewables integration.
VoltNAR
WHY VOLTNAR?
./ Due to new technologies and their declining costs, it is now possible for
electricity to reach the desired destination at appropriate voltage levels
using less energy.
WHAT'S THE RELEVANCE TO THE CLEAN POWER PLAN?
./ American Electric Power, which operates in Texas and other states, has a
VolWAR demonstration project in Ohio. The results of that study showed
energy savings of 2-3 percent with associated reductions in carbon
emissions, with net savings in cost.
WHAT HAS VOLTNAR EXPERIENCE BEEN IN TEXAS?
./ While ERCOT has used voltage reduction as a tool to respond to system
emergencies, in a recent Task Force report, it was recognized that the
deployment of smart meters and other technology allows the opportunity for
additional voltage control.
21
Packet Pg. 33
30
Attachment: 6C - CPP for Dec 2015
Minutes
BOD-FINAL2
Acceptance:
2perpg
Minutes
(3327of
: Discussion
Dec 17, 2015
and
9:00
Presentation
AM (Minutes
of PEC
Approval)
Impacts of Federal Clean Power Plan)
6.C.1.a
4.A
Clean Power Plan
PEC Board Meeting
December 17,, 2015
John D.
D Hewa
Ingmar Sterzing
VP, Power Supply & Energy Services
Don Ballard
VP,, Legal
g Services
PECHISTORY
•
Cooperative Established in 1938 with
help from then-congressman Lyndon B.
Johnson
•
In 1938, REA granted PEC a loan to build
nearly 1,800 miles of line to serve 3,000
Families and Rural Ranches
•
For about 32 years PEC
C was Exclusively
Served Emission Free Energy
•
Today Serving Some of the Fastest
Growing Counties in the US
•
y
250+ Subdivisions Underway
•
Heavy Commercial Growth
•
Rapidly Evolving Expectations
Packet Pg. 34
31
Minutes
BOD-FINAL2
Acceptance:
2perpg
Minutes
(3327of
: Discussion
Dec 17, 2015
and
9:00
Presentation
AM (Minutes
of PEC
Approval)
6.C.1.a
4.A
PECBYTHENUMBERS
274,329
Active Accounts
695
Employees
8,100
Square Miles
24
Counties
44
Franchise
Cities
$165 Million
2016 CIP Budget
10,000 Meters
E t 2015 G
Est.
Growth
th
$606,859,238
Revenue in 2015
5,343,266,603
kWh Sold in 2015
Core BusinessFocus
Service
Reliability
S f
Safety&Security
&S
i
Rates
Rates
&
EnergyFuture
Costof
Cost
of
Service
Packet Pg. 35
32
Minutes
BOD-FINAL2
Acceptance:
2perpg
Minutes
(3327of
: Discussion
Dec 17, 2015
and
9:00
Presentation
AM (Minutes
of PEC
Approval)
6.C.1.a
4.A
Balancing StrategicOutcomes
Programs Underway

EnergyInspections
EnergyEfficiencyIncentives
HighEfficiencyHVAC
EfficientCommercialLighting
StreamlinedInterconnections
andProConsumerRates
SolarOnBillFinancing
MemberandCommunitySolar
Grid Optimization
GridOptimization
DemandSideManagement
ExpandedEnergyInformation
and Alerts
andAlerts
Packet Pg. 36
33
Minutes
BOD-FINAL2
Acceptance:
2perpg
Minutes
(3327of
: Discussion
Dec 17, 2015
and
9:00
Presentation
AM (Minutes
of PEC
Approval)
6.C.1.a
4.A
INNOVATIVESERVICES
PHASEI
9Mobilememberportal
9Newwebportal
9SecurepaymentIVR
9More flexible billing
9Moreflexiblebilling
9Dynamicnotifications
9EnhancedSecurity
InProgress
• Online,realtimeoutagemap
• Prepaycompatible
• Kiosksites
ENERGYSERVICES
SERVICES
Newenergyassessmenttoolprovidesmemberswithdirectwaysto
evaluateandimprovethewaytheyuseenergy
Packet Pg. 37
34
Minutes
BOD-FINAL2
Acceptance:
2perpg
Minutes
(3327of
: Discussion
Dec 17, 2015
and
9:00
Presentation
AM (Minutes
of PEC
Approval)
6.C.1.a
4.A
PECWholesaleRenewableEnergy
• TotalRenewable– 10%(energy)
• Wind–
Wi d 6%(energy)
6% (
)
• LCRAHydroProduction
Renewable&Distributed
Energy
Shaping member options without subsidy
through community solar and on-bill financing
for individual members to make solar options
more cost effective
9 On-Bill Financing
9 Community Solar
9 Commercial Member Solar
9 Developing Advanced Rate Designs
Packet Pg. 38
35
MEMBERSOLARBYTHENUMBERS
•
•
•
•
Approx.900Interconnections
Approx
900 Interconnections
Typicalsizeresidential: 7kW
Avg cost per watt: $2 85
Avg.costperwatt:$2.85
Levelized costofelectricity
estimated $0 12 for 7 kW system
estimated$0.12for7kWsystem
over25years
5th AnnualPECHillCountrySolarTour
InstallerFair/Exhibits
•
•
•
•
•
370Attendees
370
Attendees
LocalInstallers
PECEnergyAdvisors
Solar Car Workshop
SolarCarWorkshop
TexasSolarEnergySociety
Home E hibits
HomeExhibits
• FourHomeSites
• Homeowner,solarinstallerandPEC
Staffateachlocation
• 263membervisitstohomes
Packet Pg. 39
36
Minutes
BOD-FINAL2
Acceptance:
2perpg
Minutes
(3327of
: Discussion
Dec 17, 2015
and
9:00
Presentation
AM (Minutes
of PEC
Approval)
6.C.1.a
4.A
Minutes
BOD-FINAL2
Acceptance:
2perpg
Minutes
(3327of
: Discussion
Dec 17, 2015
and
9:00
Presentation
AM (Minutes
of PEC
Approval)
6.C.1.a
4.A
ONBILLFINANCING FORMEMBERPROJECTS
• LoanAmountupto$20,000
• Termoftheloanupto10years
• OfferedtoPECResidential&Commercial
Off d PEC R id i l & C
i l
• CompetitiveInterestRates
• ConvenientlyPresentedontheMember’sBill
BeginninginJanuary2016
COMMUNITY SOLAR
• Only2227%ofRooftopsareSuitable
• OpportunityforMembersto
participateinarenewableprogram
• PECAdvancestheDeployment
• MembersreceiveBenefitsofScale
CommunitySolarleveragesCo
Community
Solar leverages Coop
op
ScaletoProvideLowCostSolar
BenefitstoMembersWithoutSubsidy
for Consumers who Cannot or Choose
forConsumerswhoCannotorChoose
nottoHostSolarontheirProperty
Packet Pg. 40
37
Minutes
BOD-FINAL2
Acceptance:
2perpg
Minutes
(3327of
: Discussion
Dec 17, 2015
and
9:00
Presentation
AM (Minutes
of PEC
Approval)
6.C.1.a
4.A
Energy inFocus
•
•
•
•
•
NonProfit
NotAboutMWHSales
OptimizeValueofOwnerAssets
EnergyFlowsinManyWays
PECasanEnabler
Energy SolutionsEnabler
MemberOwned

Renewables
Storage
EnergyEfficiency
Conservation
DemandManagement
AdvancedRates/TOU
T&DAssets
Equitable Tariffs
EquitableTariffs
Knowledge&Information
Service
Support
EnergyInspections
OnBillFinancing
Member&Communityy
Solar

ERCOT
LCRA & Others
LCRA&Others
Coal
NaturalGas
Nuclear
UtilityWind
UtilitySolar
P
Partnership
hi
Packet Pg. 41
38
Minutes
BOD-FINAL2
Acceptance:
2perpg
Minutes
(3327of
: Discussion
Dec 17, 2015
and
9:00
Presentation
AM (Minutes
of PEC
Approval)
6.C.1.a
4.A
EPA CleanPower
Plan (CPP)
Plan(CPP)
• WhatistheFederallyMandatedCPP?
y
• Reducescarbonemissionsfromfossilfuelfired
electricgeneration.
• Requiresreductionsof32%below2005levelsin
R
i
d ti
f 32% b l
2005 l l i
2030.
• Statesareresponsibleforimplementationwith
States are responsible for implementation with
StatePlansduetotheEPAbySeptember2016.
• Texas’s2030goalis1,042lb CO2/MWh.
WhyisThis Significant
to
toPEC
PEC
• Reliability,Rates,
WholesaleContracting,
andRenewableEnergy
Partnerships
• FuelDiversity
• LongtermPlanning
• EconomicDevelopment
Packet Pg. 42
39
BACKGROUND ERCOTOVERVIEW
•
•
•
•
•
•
Consumers:24Million
PeakDemand:Nearly70GW
G
GenerationCapacity:74,000MWfrom550generatingunits
i C
i
74 000 MW f
550
i
i
MarketParticipants:1,100+thatgenerate,move,buy,selloruse
Advancedmeters:6.6Millionwith97percentofERCOTloadincompetitive
areassettledona15minuteintervalbasis
Morethan2,100MWindemandresponseresources
ERCOTservesthepublicbyensuringareliablegrid,efficientelectricitymarkets,
openaccessandretailchoice.
ENERGY FREQUENCYREGULATION EMERGENCYRESPONSE
BACKGROUND – 2014ENERGYMIX
UNITEDSTATES
Hydro,
Other
10%
Energy(MWh)
(
)
ERCOT
Wind
11%
LCRA
Hydro,
Other
1%
Energy(MWh)
Wind
4%
Energy(MWh)
Hydro,
Other
1%
Wind
5%
Natural
Gas
27%
Coal
39%
Coal
36%
Naturall
Gas
47%
Natural
Gas
41%
Nuclear
19%
Nuclear
11%
Coal
48%
Nuclear
0%
Packet Pg. 43
40
Minutes
BOD-FINAL2
Acceptance:
2perpg
Minutes
(3327of
: Discussion
Dec 17, 2015
and
9:00
Presentation
AM (Minutes
of PEC
Approval)
6.C.1.a
4.A
WhatourOwners
Need to Know
NeedtoKnow
•
•
•
•
•
Minutes
BOD-FINAL2
Acceptance:
2perpg
Minutes
(3327of
: Discussion
Dec 17, 2015
and
9:00
Presentation
AM (Minutes
of PEC
Approval)
6.C.1.a
4.A
LCRA
Maintainingandactivepowersupply
g
pp
g
managementapproachcanmitigatethe
impactoftheCPPonPECrates
LCRA’sdiversepowersupplyincludes
1,275MWofcoalgenerationand595MW
g g
ofnaturalgasgenerationthatare
potentiallyimpactedbytheCPP
ERCOTestimatesthattheenergycostto
serveloadcouldincrease44%compared
y
tothebaselineby2030
BasedonsimilarassumptionsandPEC’s
recentlyIntegratedResourcePlan(IRP),
PEC’spowersupplycostcouldincrease
p
y
27%comparedtothebaselineby2030
PEC’sestimatedpowersupplycostin2030
withoutCPP$450MMandwithCPP$570
MM
WhatareweReally
WhatareweReally
Talking About . . . The Controversy?
TalkingAbout...TheControversy?
Packet Pg. 44
41
Minutes
BOD-FINAL2
Acceptance:
2perpg
Minutes
(3327of
: Discussion
Dec 17, 2015
and
9:00
Presentation
AM (Minutes
of PEC
Approval)
6.C.1.a
4.A
Massive FuelSwitch
• In
In14Years
14 Years
• MeetnewLoadGrowth.....Plus
• ReplacethousandsofMWofcapacitywithnatural
Replace thousands of MW of capacity with natural
gas....andrenewables
What aretheUncertainties?
•
•
•
•
•
•
•
•
EnvironmentalOutcomes
CostsandImpacts
FuelDiversity
FuelandPipelineDependencies
NaturalGasStorage
ElectricTransmissionInfrastructure
ElectricDistributionInfrastructure
Technology
Packet Pg. 45
42
Minutes
BOD-FINAL2
Acceptance:
2perpg
Minutes
(3327of
: Discussion
Dec 17, 2015
and
9:00
Presentation
AM (Minutes
of PEC
Approval)
6.C.1.a
4.A
What Opportunities?
•
•
•
•
•
•
•
EfficientPowerPlants
Efficient
Power Plants
DistributedEnergyResources
Renewables
EnergyEfficiency
Advanced Technologies
AdvancedTechnologies
TXNaturalGas
Reduce Mercury Sulphur CO2
ReduceMercury,Sulphur,CO2
Risks?
Federal
Energy
?
Policy
•
•
•
•
•
“Uncoordinated”FuelSwitch
“U
di t d” F l S it h
RegulatoryBodies Uncertainty
Federal Energy Policy
FederalEnergyPolicy
U.S.CongressVotedAgainstCPP
National Security?
NationalSecurity?
Strategy?
Packet Pg. 46
43
Whatdo ReliabilityExpertssayAboutCPP?
• NERC
NERCStudy:
Study: “The
TheimplementationoftheCPPcouldleadtoresourceadequacyand
implementation of the CPP could lead to resource adequacy and
electricinfrastructureconstraintsandwillhavesignificantimpactsonplanningand
operationofERCOT”
• FERCStudy:
FERC Study: “EPA
EPAfinalruleshouldprovideenoughtimeandflexibilityforaffected
final rule should provide enough time and flexibility for affected
entitiestotaketheactionsthattheymusttaketoensuresystemreliability.These
actionscouldincludetheconstructionofgasorelectricinfrastructuretosupportthe
addition of new capacity ”
additionofnewcapacity.”
• ERCOTStudy: “Atleast4,000MWofcoalunitretirementsduespecificallytotheClean
PowerPlan.AdditionalcoalunitretirementswhenRegionalHazeisconsidered,likely
to occur before the Clean Power Plan compliance timelines Up to 23 000 MW of solar
tooccurbeforetheCleanPowerPlancompliancetimelines.Upto23,000MWofsolar
andwindadditionsinscenarioswiththeCleanPowerPlan,resultinginalmost44,000
MWtotalintermittentrenewablecapacity.”
• “IfERCOTdoesnotreceiveadequatenotificationoftheretirementsandifmultiple
“If ERCOT d
t
i
d
t
tifi ti
f th
ti
t
d if
lti l
unitretirementsoccurwithinashorttimeframetherecouldbeperiodsofreduced
systemwideresourceadequacyandlocalizedreliabilityissues.”
Whatdo
WhatdoEconomicExperts
EconomicExperts
say About CPP?
sayAboutCPP?
• ERCOT: CPPcouldseeincreaseinresidentialretailelectricityratesup
to818%by2030
• Brattle: ForERCOT,onaverage,energypriceswouldincreasebetween
$10 $45/MWh
$10$45/MWh
• NERAEconomicConsulting: Deliveredelectricitypriceswouldincrease
byabout1217%onaverageover2017through2031(nationally)
• AnalysisGroup:
A l i G
I
ImpactsonelectricityratesfromwelldesignedCO
l
i i
f
ll d i d CO2
pollutioncontrolprogramswillbemodestinthenearterm,andcanbe
p
y
g
y
accompaniedbylongtermbenefitsintheformoflowerelectricitybills
andpositiveeconomicvaluetostateandregionaleconomies.
Packet Pg. 47
44
Minutes
BOD-FINAL2
Acceptance:
2perpg
Minutes
(3327of
: Discussion
Dec 17, 2015
and
9:00
Presentation
AM (Minutes
of PEC
Approval)
6.C.1.a
4.A
Minutes
BOD-FINAL2
Acceptance:
2perpg
Minutes
(3327of
: Discussion
Dec 17, 2015
and
9:00
Presentation
AM (Minutes
of PEC
Approval)
6.C.1.a
4.A
Whatdo
WhatdoEnvironmental
Environmental
Experts say About CPP?
ExpertssayAboutCPP?
• EPA: CPPimplementedwillreduceCO2 pollutionby32%,sulphur oxideby
90% nitrogen oxides by 72% below 2005 levels lead to a transition to clean
90%,nitrogenoxidesby72%below2005levels,leadtoatransitiontoclean
energyandhaveclimatebenefitsof$20B,healthbenefitsof$14$34Band
netbenefitsof$26$45B.
• EnvironmentalDefenseFund:
E i
t lD f
F d CurrenttrendsinTXwillfulfillthe20222029
C
t t d i TX ill f lfill th 2022 2029
interimCPPgoalsandcarryTX88%ofthewaytoachievingthe2030goal.
• SierraClub: TheCPPdoesn’tsolvetheproblemofclimatedisruptionbyitself,
butitgivesusaframeworktomakesignificantprogressinthestates.
• NationalDefenseResourcesCouncil: BenefitsofreducingCO2 andthe
traditionalpollutantsarebothsubstantial,addingupto$28billionto$63
billionacrossthecasesin2020,yieldingnetbenefitsrangingfrom$21billion
to$53billion
StatusofCPP
Statusof
CPP
• Regulatory
• FinalRuleAnnounced:August3,2015
• FinalRulePublished:October23,2015
Rules Effective: December 22 2015
• RulesEffective:December22,2015
• StatePlandue:September6,2016
• Legislative
• “Ratepayer
RatepayerProtectionActof2015
Protection Act of 2015”
U.S.HousevotestodelayCPPandallowstatesto“optout”ifstatecertifies
“significantadverseimpactonelectricityratepayersorreliabilityofstate
y
]
electricsystem.”H.R.2042]
• U.S.Senatevotesto“disapprove”andnullifyCPP[S.J.Res.24]
• Litigation
• 24StatesfiledchallengetoCPP
• NRECAfiledchallengewith37G&TCoops
• 80industryortradeassociationspetitioners
Packet Pg. 48
45
Minutes
BOD-FINAL2
Acceptance:
2perpg
Minutes
(3327of
: Discussion
Dec 17, 2015
and
9:00
Presentation
AM (Minutes
of PEC
Approval)
6.C.1.a
4.A
OpportunityforEngagement
Opportunityfor
Engagement
• PEC’sRole
• NRECAtakingaleadershiproleinopposition.
• Legalchallenge
L l h ll
• NRECAlitigationcounselnamedasliaisontoCourt
TEC leadership
• TECleadership.
• Communication,Education,Testimony
• LCRA
• Testimony,Communication,Analysis
• PECEngagement
• AmicusCuriaeandLitigation
A i
C i
d Liti ti
• NoDirectCoststoPEC
ARegulatoryMandateWithout
aPlan....
Pl
Packet Pg. 49
46
Minutes
BOD-FINAL2
Acceptance:
2perpg
Minutes
(3327of
: Discussion
Dec 17, 2015
and
9:00
Presentation
AM (Minutes
of PEC
Approval)
6.C.1.a
4.A
Packet Pg. 50
47
6.C.2
4.A
Board of Directors
Meeting: 12/17/15 09:00 AM
PO Box 1
RESOLUTION 2015-99
DOC ID: 3279
Subject: Authority to File Amicus Curiae Brief
Submitted By: Ingmar Sterzing
Background:
Under the Cooperative’s Authority and Responsibilities Policy (a.k.a “Delegation of Authority”),
the Board authorizes the initiation or setting of strategic direction of litigation and governmental
advocacy. The Board also approves Legislative Positions before Congress or the Legislature
under its Legislative Policy. It is the policy of the Board of Directors of Pedernales Electric
Cooperative to develop electric rates that allow the Cooperative to provide low-cost energy
services that are reliable, cost based, considerate of the environment and maintain the
Cooperative’s financial strength. (PEC Rate Policy).
On October 23, 2015, the Environmental Protection Agency (EPA) published its final rule on
new source performance standards ("NSPS") under the Clean Air Act ("CAA") section 111(b)
that establishes standards for emissions of carbon dioxide (CO2) for newly constructed,
modified, and reconstructed affected fossil fuel-fired electric utility generating units ("EGUs"). 40
C.F.R Parts 60, 70, 71, and 98. The rules establish separate standards of performance for fossil
fuel-fired electric utility steam generating units and fossil fuel-fired stationary combustion
turbines. The rules also establish emission guidelines for states to use in developing plans to
limit CO2 emissions from existing fossil fuel-fired EGUs. The final rules are commonly referred
as “The Clean Power Plan ("CPP").” The CPP creates a process for EPA to set a state CO2
emissions goal and the state to choose how they will meet it. The Electric Reliability Council of
Texas ("ERCOT") model based on different scenarios indicates that compliance with CPP will
impact electricity prices in the ERCOT region. By 2030 compliance with CPP results in a 2044% increase in locational marginal prices ("LMPs") relative to the baseline, which would result
in an 8-18% increase in retail energy prices. There could also be increased challenges with
maintaining reliability due to coal-fired units being retired and introduction of more intermittent
renewable energy.
Immediately after publication of the final rules, many parties filed suit challenging the rules by
seeking review in the U.S. Court of Appeals, District of Columbia Circuit. The National Rural
Electric Cooperative Association (NRECA) and the State of Texas are examples of litigants. The
states’ case is West Virginia, et. al. v. United States Environmental Protection Agency, et. al.;
Cause No. 15-1363 (D.C. Circuit) (filed October 23, 2015). It is expected that the Court of
Appeals will consolidate all of the petitions challenging the rules.
The PEC Board may now consider whether and how to participate in the challenge to the CPP.
There are 2 primary arguments challenging the rules: the first based upon regulatory and
rulemaking authority (“Structural Arguments”) that EPA is outside its statutory authority or failed
to comply with the rulemaking requirements of its enabling statute or Administrative Procedure
Act; the second involves constitutional challenges primarily surrounding 10th Amendment and a
state’s “police power” (“Federalism Arguments”).
PEC would seek assistance from the Center for the American Future associated with the Texas
Public Policy Foundation and the Pacific Legal Foundation. The Center has committed to
drafting and filing a pleading at no cost on behalf of PEC utilizing the Structural and Federalism
Updated: 1/14/2016 11:56 AM by Renee Oelschleger
Packet Pg. 51
48
Page 1
Department: Power Supply & Energy Services
6.C.2
4.A
Arguments. PEC would file an amicus curiae brief in support of the state and other entities
challenging implementation of the new EPA rules. By filing an amicus brief. PEC would not be a
party to the litigation; rather, a friend of the court” in providing supplemental arguments. The
amicus brief may also involve a Motion for Leave to File with the Court under Rule 29 of the
Federal Rules of Appellate Procedure which would also be handled by the Center’s counsel.
Financial Impact and Cost/Benefit Considerations:
Expenditure of Cooperative funds estimated in the amount of $0 included in the Cooperative's
2015 operating budget); expenditures of staff time estimated in amount of 0 hours (other than
ordinary processing requirements).
ATTACHMENTS:
PEC Oversight of EPA's Clean Power Plan - Scanlon substitute resolution 2015-12-17 (PDF)

Packet Pg. 52
49
6.C.2
4.A
Pedernales Electric Cooperative, Inc.
Regular Meeting
December 17, 2015
RESOLUTION 2015-99
Authority to File Amicus Curiae Brief
RESULT:
MOVER:
SECONDER:
AYES:
NAYS:
BE IT RESOLVED BY THE BOARD, that the Board directs staff to produce an amicus brief
for the limited purpose of educating the court and raising awareness of the real effects of
this Clean Power Plan on Pedernales Electric Cooperative, its members and citizens alike.
ADOPTED [4 TO 3]
Amy Lea SJ Akers, District 7 Director
Emily Pataki, Paul Graf, Amy Lea SJ Akers, James Oakley
Cristi Clement, Kathryn Scanlon, Chris Perry
Packet Pg. 53
50
Page 3
Regular Meeting
December 17, 2015
RESOLUTION (ID #####)
PEC Oversight of EPA’s Clean Power Plan
WHEREAS, Pedernales Electric Cooperative, Inc. (“PEC”) is a democratic organization
controlled by its members, who actively participate in setting policies and making decisions;
WHEREAS, The Clean Power Plan is implemented at the federal level with potentially
inadequate rate protections for PEC members in regard to costs, impacts, and PEC’s portfolio
resource management for power supply;
NOW THEREFORE, BE IT RESOLVED BY THE BOARD, that Board directs the CEO to
monitor, access and regularly report to the Board regarding the progress of the Clean Power
Plan implementation presenting the impact and to any cost to Members whenever data is
sufficiently reliable to be reported. Collaboration with LCRA and PEC’s power providers is
encouraged in monitoring and reporting to the Board and Membership on the impacts.
BE IT FURTHER RESOLVED, that the Chief Executive Officer, or his designee, is authorized to
take all such actions as needed to implement this resolution.
Updated: 12/15/2015 9:32 AM by Lana Freudenberg
Packet Pg. 54
51
Page 3
Attachment: PEC Oversight of EPA's
Minutes
Clean
Acceptance:
Power Plan
Minutes
- Scanlon
of Dec
substitute
17, 2015
resolution
9:00 AM 2015-12-17
(Minutes Approval)
(RES-2015-99 : Authority to File Amicus
6.C.2.a
4.A
Director Kathy Scanlon's substitute motion which was later withdrawn.
8.A
4.A
Board of Directors
Meeting: 12/17/15 09:00 AM
PO Box 1
RESOLUTION 2015-108
DOC ID: 3329
Subject: Compliance and Qualifications Question of Director Chris Perry to Affirm Directors
Code of Conduct Submitted By: Renee Oelschleger
Department: Legal Services
Expenditure of Cooperative funds estimated in the amount of $0 included in the Cooperative's
2016 operating budget; expenditures of staff time estimated in amount of 0 hours (other than
ordinary processing requirements).
Packet Pg. 55
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Page 1
Background:
8.A
4.A
Regular Meeting
December 17, 2015
RESOLUTION 2015-108
BE IT RESOLVED BY THE BOARD, that the Board instructs Director Chris Perry that he has
until the adjournment of the next scheduled meeting, January 11th to sign an unabridged
unqualified version of the Code of Conduct as we all have had to do as sitting directors.
RESULT:
MOVER:
SECONDER:
AYES:
ABSENT:
ADOPTED [UNANIMOUS]
Chris Perry
Packet Pg. 56
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Page 2
Compliance and Qualifications Question of Director Chris Perry to
Affirm Directors Code of Conduct - Notice to Comply
8.B.1
4.A
2016 Election Timeline
Annual Decision (Election Services
Contract)
Establish Annual Meeting Date and
Location
Section Party
Due Date
At or before the August Regular
Board Meeting
Board Meeting
At least 6 months prior to Annual
Meeting
At or before the January Regular
Board Meeting
Meeting
11/13/2015
Upon approval of the Election
Timeline
1/19/2016
None specified/continuing
1/19/2016
Meeting
1/19/2016
Meeting
1/19/2016
At least a week before the Regular
Board meeting 4 months prior to an
election
2/8/2016
Before the February Regular Board
Meeting (timeline reflects Board
packet deadline).
2/15/2016
6.2.1.6 BOD/QC
At the Regular Board meeting 4
months before an election
2/15/2016
Candidate
6.2.1.4
Applicants/BRS
At or before 5 p.m. on the last
business day falling 82 days or more
before the date of the Annual
Meeting
3/28/2016
4.1
GC/BOD
3.1
BOD
Present Election Timeline
3.2
GC
Communications plan presented to
the Board of Directors
7.3
Communications
Department
Approve Election Timeline
3.2
BOD
GC/Communicatio
ns/IT/Board
Conduct Internal Coordination
Recording
Meeting and Establish PEC Election
3.3
Secretary/Legal/M
Team
ember
Services/SBS
Retain Background Verifier
6.2.1.7 GC
Post and make available Ballot
BRS/Communicati
6.2.1.1.1 ons/Member
Materials and Nomination
Application
Services
Direct the General Counsel to
prepare proposed Non-Director
6.1
BOD
Election items
Director will submit to the Board
Recording Secretary the name of a
person or persons residing in the
Director’s District eligible and willing
to serve on the Qualifications and
Elections Committee
Send Quality Control steps to the
General Counsel
Board will appoint the Qualifications
and Elections Committee
Candidate Application to be
delivered to the Board Recording
Secretary at PEC Headquarters in
Johnson City
Qualifictions and Elections
Committee Meeting Date
2015-2016
Deadline**
6.2.1.6 BOD/BRS
7.13
SBS/GC
QEC/OGC/BRS
Candidate
7.1, 7.6 Applicants/PEC
staff
Election withdrawal deadline for
Candidate
7.2
removal from Ballot
Applicants
Presentation and approval of
Qualifications and
6.2.1.9,
Candidate slate, Ballot, and any NonElections
6.2.1.10
Director Election items
Committee /GC
Candidate
Candidates video recording
7.5
Applicants/PEC
staff
Candidate Orientation and
Candidate photographs
1
2/17/2015
8/18/2015
1/11/2016
1/19/2016
4/12/2016
The week preceding the April
Regular Meeting of the Board
4/13/2016
Before Board approval of Ballot
4/18/2016
At least 2 months prior to an election
4/18/2016
On the Thursday after the Ballot is
approved by the Board
4/21/2016
Packet Pg. 57
54
Attachment: 2016 Election
Minutes
Timeline
Acceptance:
FINAL wMinutes
highlights
of Dec
(3326
17, :2015
Announcement
9:00 AM (Minutes
of 2016Approval)
Election Timeline - D Richards)
Item
8.B.1
4.A
Item
Section Party
Due Date
2015-2016
Deadline**
Mailing of Ballots
7.4.1
SBS
Delivered between 25 and 30 days
before the Annual Meeting*
5/19/2016
Online voting site goes live
7.4.2
SBS
30 days before the Annual Meeting
5/19/2016
Initial voting email notifications
7.4.3
SBS
5/19/2016
Supplemental mailing of ballots to
Members since previous mailing
Between 25 and 30 days before the
Annual Meeting
7.4.1
SBS/IT
As specified in this timeline
5/26/2016
Update on voter turnout
7.12
GC
7.12
GC
7.4.1
SBS/IT
Reminder voting emails
7.4.3
SBS
Update on Voter Turnout
7.12
GC
Deadline for mailing or webcasting
advance ballots
8.4
SBS
Eight days before Annual Meeting
6/10/2016
Record Date for Casting Ballot at
Annual Meeting, transmittal by PEC
of Members eligible to vote to SBS
5.2
IT
Close of business four business
days before Annual Meeting
6/14/2016
Pre-Annual Meeting Quality Control
7.14
SBS
Post-Tabulation, Pre-Announcement
Quality Control
8.8
SBS
Announcement and Certification
8.9
SBS
Post-Election Director
Acknowledgments
8.10
BOD
District-by-District Results
9.1
SBS
Post-Election Analysis
9.2
GC
Once weekly after ballots are initially
mailed
Once weekly after Ballots are initially
mailed
Dates to be determined each year
when timeline presented to the
Board of Directors
mailed
At the close of the final business day
before the Annual Meeting
On the date of Annual Meeting after
the results are tabulated
the meeting has concluded
Within five business days of the
Annual Meeting
Within two months after the Annual
Meeting
5/26/2016
6/2/2016
6/2/2016
5/26/2016
6/2/2016
6/9/2016
6/17/2016
6/18/2016
6/18/2016
6/18/2016
6/24/2016
8/18/16
*Ballots are mailed for intended delivery to Members on the first day of voting period. It is anticipated that U.S. addresses will be
mailed 3 days in advance and international addresses 10-15 days in advance of the first day of voting.
**Dates listed here are subject to change due to aligning dates of the Board of Directors Meetings
2
Packet Pg. 58
55
Attachment: 2016 Election
Minutes
Timeline
Acceptance:
FINAL wMinutes
highlights
of Dec
(3326
17, :2015
Announcement
9:00 AM (Minutes
of 2016Approval)
Election Timeline - D Richards)
9.A
4.A
Board of Directors
Meeting: 12/17/15 09:00 AM
PO Box 1
RESOLUTION 2015-107
DOC ID: 3298
Subject: 2016 NRECA/NRTC/CFC Annual Meetings Voting Delegates
Submitted By: Renee Oelschleger
The NRECA Annual Meeting will be held in New Orleans from February 14-17, 2016. NRECA
requires voting delegates to cast votes in person at the business meeting on Tuesday, February
16, 2016.
NRTC Annual Meeting will be held Sunday, February 14 from 2:30 - 4:00 pm.
CFC Annual Meeting will be held Monday, February 15 from 2:30 - 4:00 pm. CFC Bylaws
permits members to cast ballot by mail.
HISTORY:
12/07/15
Board of Directors
RECOMMENDED
Next: 12/17/15
$0 financial impact; costs for attendance at meeting by directors; no expenditures of staff time
other than ordinary processing requirements.
ATTACHMENTS:

Signed Voting Delegate Form 2015-12-17
(PDF)
Updated: 1/10/2016 7:54 PM by Renee Oelschleger
Packet Pg. 59
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Page 1
Background:
The Board may consider designation of voting delegates and alternates to upcoming NRECA,
NRTC, and CFC annual meetings.
9.A
4.A
Regular Meeting
December 17, 2015
RESOLUTION 2015-107
BE IT 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 an alternate delegate to act at meetings of the
2016 National Rural Electric Cooperative Association (NRECA) Annual and Regional Meetings
until successors are duly appointed and designated: Kathy Scanlon, Voting Delegate; and
James Oakley, Alternate Delegate.
BE IT FURTHER 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 act at the 2016 National Rural Telecommunications Cooperative (NRTC)
Annual Meeting until successors are duly appointed and designated: Kathy Scanlon, Voting
Delegate; and James Oakley, Alternate Delegate; and
that the following Director is hereby appointed and designated as an authorized representative
of the Cooperative to serve as the voting delegates of the Cooperative and to cast the vote of
the Cooperative for matters pertaining to the 2016 District 10 Meeting of the National Rural
Utilities Cooperative Finance Corporation (CFC): Kathy Scanlon, Official Voting Delegate; and
James Oakley, Alternate Delegate; and
BE IT FURTHER RESOLVED that the Chief Executive Officer or his designee is authorized to
take such actions necessary to implement this resolution.
RESULT:
MOVER:
SECONDER:
AYES:
ABSENT:
ADOPTED [UNANIMOUS]
Chris Perry
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Page 2
2016 NRECA/NRTC/CFC Annual Meetings Voting Delegates
9.A.a
4.A
Regional Meeting
Voting Delegate Certification
And Credentiaiing Process
National Rural Electric
Cooperative Association
•
I»
-
"T~&.c:rn·Qqoaatl", 4....
Please fill out the form below. Indicate who will be your Voting Delegate for 2016 and an Alternate in
case the Delegate is unable to attend the Business Meeting. You will have an opportunity to select a new
delegate for the 2016 Regional Meetings. Please return this form to NRECA using the following
email address: VotingDelegates@nreca,coop or this fax number: (703) 907·5512.
State: Texas
To: John O. Hewa Pedemales Electric Co-op, Inc.
PO Box 1
Johnson City, TX 78636·0001
NRECA VOTING DELEGATE CERTIFICATION
NRECA Bylaws Arttde V, SectIon 2(B) and 2{C) provide that "...each voting member shall be entftled to select, either by vote of Its
membership or Its board of directors, one of Its members, directors, or employees to act as the IIOting delegate, and one such person to
act as the altemate delegate, at the meellng...each IIOtlng delegate must submit a certification signed by the director who Is president of
the member or is chair of the member's board of directors, and by the director who Is secretary of the member, stating that such delegate
Is duly authorized to cast the vot~ of the member.H
Please Indicate below who Will be your delegate at the 2016 NRECA Annual Meeting. Only those delegates who have been
properly documented as authorized by their cooperatives shall be aedentialed to act during the NRECA Annual and
Regional Meeting Business 5esston. 11115 form must be dated, signed by the board President and board Seaetary (board
of dlrectorsf trustees), and returned to NRECA by JanuarY 11. 2016. You wlll have an opportunity to select new delegates for
the 2016 Regional Meetings.
The followln, are hereby certified as official voting d elegate and altemate and are dulVautho rized t o cast tlte vote of this member.
2016 Voting Delegate
Name
Kathy Scanlon ntle Director
2018 Alternate Delegate
Name James Oakley
nile Board President
(n<·-·zti12'7~~;-1
Signed Board PFldent (of Memb€j- ~em)
~,;'~
DATE
y~/
Board Secretary (of ~ System)
/2.. -/~ -IS'
DATE
Meeting and Delegate Registration Procedures
II Please retum signed, dated and completed fonn
to [email protected] by January 11th,
2016.
!d Delegates must be negistered for the meeting in
advanc~
and should pick up their badge before
checking in as a delegate.
Ii At the meeting the delegate must then proceed to
the Voting Delegate registration Desk which will be
located near the general NRECA Meeting Registration
area.
m
At the NRECA Voting Delegate Registration Desk, the
delegate's certification infonnation will be reviewed and the
delegate will re<:eive the official delegate ribbon. which will
be attached to the name badge, as well as the assigned
credential card for the meeling.
The delegate must bring the credential card and ribbon
to the NRECA BUSiness Meeling and present it in order to
vote. Each voting member is pennlt1ed one vote on each of
the resolutions and other business properly brought before
rs
the Annual and Regional Business Sessions. No
Individual may represent more than one voting member
system and proxy voting Is prohibited.
1/ )IOU hOlle ony questions concerning the above procedure, pletlse contact the Membership Deportment Dt (703) 901-5868.
Packet Pg. 61
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Attachment: Signed Voting Delegate
Minutes Acceptance:
Form 2015-12-17
Minutes
(RES-2015-107
of Dec 17, 2015
: 2016
9:00
NRECA/NRTC/CFC
AM (Minutes Approval)
Annual Meetings Voting Delegates)
NRECA 2016 Annual and
10.B.2
4.A
Board of Directors
Meeting: 12/17/15 09:00 AM
PO Box 1
RESOLUTION 2015-102
DOC ID: 3309
Subject: 2016 Key Performance Indicator Plan and Methodology -M Racis
Submitted By: Michael Racis
Background:
The Board of Directors desires to adopt a Key Performance Indicator ("KPI") Plan for the 2016
calendar year (the "2016 KPI Plan") to provide an objective method for calculating performancebased financial distributions for eligible employees who contribute to the advancement of the
goals and initiatives.
The financial impact of the proposed 2016 KPI Plan will not be known until after the full KPI Plan
Year concludes on December 31, 2016
ATTACHMENTS:

2016 KPI Recommendations BOD JHewa 12_17_2015_Final 2perpg

2016 KPI Plan_Final
(PDF)
(PDF)
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Page 1
Department: Communications and Business Services
10.B.2
4.A
Regular Meeting
December 17, 2015
RESOLUTION 2015-102
2016 Key Performance Indicator Plan and Methodology - J Hewa / M
Racis
BE IT RESOLVED BY THE BOARD OF DIRECTORS that the 2016 KPI Plan presented to the
Board this day with is hereby approved and adopted; and
BE IT FURTHER RESOLVED that the Chief Executive Officer, or his designees, are hereby
authorized and directed to take any and all actions as may be necessary or desirable to
implement the 2016 KPI Plan and otherwise effectuate the purposes of this resolution.
RESULT:
MOVER:
SECONDER:
AYES:
ABSENT:
ADOPTED [UNANIMOUS]
Chris Perry
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Page 2
Attachment: 2016 KPI Recommendations
Minutes Acceptance:
BOD JHewa Minutes
12_17_2015_Final
of Dec 17, 2perpg
2015 9:00
(RES-2015-102
AM (Minutes:Approval)
2016 Key Performance Indicator Plan and
10.B.2.a
4.A
2016 Key Performance Indicator (KPI) Plan Recommendations
(KPI) Plan Recommendations
John Hewa, CEO
John
Hewa, CEO
Michael Racis, VP Communications & Business Services
Business Services
Board of Directors Meeting
12/17/2015
2016 KPI Plan Development
2016 KPI Plan Development
KPI Plan ‐ Purpose + Objective
• Provide objective measures for evaluating PEC’s j
g
business performance against PEC’s strategic goals and calculating performance‐based financial incentive for eligible employees to contribute to the advancement of the goals and initiatives.
Packet Pg. 64
61
10.B.2.a
4.A
Minutes Acceptance:
BOD JHewa Minutes
12_17_2015_Final
of Dec 17, 2perpg
2015 9:00
(RES-2015-102
2016 KPI Plan Recommendations
Continue:
• Biannual reporting and distribution of KPIs
p
g
– Continued focus on performance throughout year
– Mid‐year review can improve end‐of‐year performance
• KPI plan on a calendar year
KPI plan on a calendar year
– PEC uses standard calendar year for work plans
– Aligns with fiscal year for budget
– Matches standard industry reporting – CFC, KRTA, OSHA
• Focus KPI measures on Safety, Reliability, Member Satisfaction and Financial Responsibility
Satisfaction and Financial Responsibility
Change:
• Align metrics and measures with Board approved Strategic Plan (5 19 15)
Strategic Plan (5.19.15)
• Evolve metrics based on past PEC scores and industry comparisons to develop “stretch”
industry comparisons to develop stretch goals goals
to improve co‐op performance
p
• Eliminate the cap on individual KPI distribution for eligible employees
• Eliminate “adders” and recalculate distribution percentage for each measure
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62
2015 S f t T t l C
2015 Safety: Total Case Incident Rate (TCIR)
I id t R t (TCIR)
Silver
Gold
Platinum
Weighting
≤ 2.7
≤ 2.1
≤ 1.5
10%
Measures OSHA‐
recordable injuries/illnesses
Score as of October 31, 2015 1 23
1.23
Platinum
2016 Recommendation: Safety‐TCIR Measurement
Silver
Gold
Platinum
Weighting
Total Case Incident Rate
(TCIR)
≤ 1.5
≤ 1.2
≤ 1.0
10%
•Recommendation/Rationale
/
•Continue use of this OSHA metric so as to compare our recordable incidents safety performance against, national, state and local averages within our business group. •Projected benchmark better than National average (3.2) •Increasing current levels to promote a higher standard of safety performance.
•A Platinum performance would hold reportable incidents (including minor
•A Platinum performance would hold reportable incidents (including minor cuts, scrapes, twisted ankles, etc.) to less than seven across a workforce of approximately 700.
•Proposed Calculation
Total Number of OSHA Recordable Injuries/Illnesses X 200,000
Total Hours Worked
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63
Minutes Acceptance:
BOD JHewa Minutes
12_17_2015_Final
of Dec 17, 2perpg
2015 9:00
(RES-2015-102
10.B.2.a
4.A
2015 S f t D
2015 Safety: Days Away Restricted Duty (DART
A
R t i t d D t (DART)
Silver
Gold
Platinum
Weighting
≤ 1.0
≤ 0.8
≤ 0.66
10%
Measures OSHA‐
recordable injuries/illnesses resulting in
resulting in restricted duty
Score as of October 31, 2015 0.88
Silver
2016 Recommendation: Safety‐DART d i
f
Measurement
Silver
Gold
Platinum
Weighting
Days Away Restricted Duty
(DART)
≤ 0.89
≤ 0.59
≤ 0.30
10%
•Continue use of this OSHA metric so as to compare our days away, restricted and/or transferred incidents performance against, restricted and/or transferred incidents
performance against
national, state and local averages within our business group. •Projected benchmark better than National average (1.7)
•A Platinum performance would hold incidences involving time away from work (“lost time”) to two or less annually across a workforce of approx. 700.
Total Number of Lost Time/Restricted Duty Injuries/Illnesses X 200,000
Total Hours Worked
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64
Minutes Acceptance:
BOD JHewa Minutes
12_17_2015_Final
of Dec 17, 2perpg
2015 9:00
(RES-2015-102
10.B.2.a
4.A
10.B.2.a
4.A
Silver
Gold
Platinum
Weighting
g
g
≤ 66 minutes
≤ 60 minutes
≤ 54 minutes
20%
Projected SAIDI at end KPI‐P2
Minutes Acceptance:
BOD JHewa Minutes
12_17_2015_Final
of Dec 17, 2perpg
2015 9:00
(RES-2015-102
2015 Reliability: KPI
2015
Reliability: KPI‐P2
P2 System Average Interruption System Average Interruption
Duration Index (SAIDI)
Measures outage time (in minutes) per member served
Score as of October 31, 2015 TO BE UPDATED
TO BE UPDATED
56.2/67.4
/
No Ranking
2016 R
2016 Recommendation: Reliability ‐
d ti
R li bilit SAIDI
Measurement
System Average Interruption Duration Index (SAIDI) calculated excluding planned, transmission, and major weather events
Silver
Gold
Platinum
KPI-P1
KPI-P1
< 33 minutes < 30 minutes
KPI-P1
< 27 minutes
KPI-P2
<66 minutes
KPI-P2
< 54 minutes
KPI-P2
< 60 minutes
Weighting
10%
•Maintain the SAIDI KPI as it is an industry standard measure of reliability
•Keep the metric levels from 2015 as they are a high standard, but have been K
th
ti l l f
2015 th
hi h t d d b t h
b
achievable in the past for PEC.
•PEC 4 year average is 57.02 minutes
•State 4 year average is 89.19 minutes (2010-2014)
•Consider introduction a SAIFI KPI in 2016, once systems have been C id i t d ti
SAIFI KPI i 2016
t
h
b
implemented to provide accurate measurement.
p
Sum of All Member Interruption Durations
Total Number of Meters Served
x 60
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65
10.B.2.a
4.A
Silver
Gold
Platinum
Weighting
≥80
≥82
≥84
10%
Minutes Acceptance:
BOD JHewa Minutes
12_17_2015_Final
of Dec 17, 2perpg
2015 9:00
(RES-2015-102
2015 S ti f ti
2015 Satisfaction: ACSI
ACSI
M
Measures ability bili
to meet member expectations; calculated by averaging two
averaging two quarterly scores and rounding
Score reported as of October 31, 2015 79
N R ki
No Ranking
2016 Recommendation: Satisfaction ‐ ACSI Measurement
Silver
Gold
Platinum
Weighting
ACSI Satisfaction Score
≥80
≥82
≥84
10%
Recommendation/Rationale
•Maintain ACSI as a measure of member satisfaction as it is utilized by co‐ops, utilities and other industries as uniform and independent measure of satisfaction. •Keep metrics (silver, gold, platinum) consistent with 2015 levels as they represent strong goals for PEC performance.
• PEC's 3Q 15 ACSI score of 79 is above the Board goal of the top quartile of all utilities and hi h h
higher than the Touchstone Energy cooperative average, the Other Co‐op average, the Top IOU h T h
E
i
h Oh C
h T IOU
and the Avg IOU.
• While PEC's ACSI score has held steady, industry scores and the TSE benchmark have decreased over the past year. The TSE benchmark is currently 82
•Consider a longer term stretch goal to be in the top ten JD Power scores within two years (currently
•Consider a longer term stretch goal to be in the top ten JD Power scores within two years (currently PEC's score ranks 21 of the 146 utilities).
KPI-P1:
2015 Q4 ACSI + 2016 Q1 ACSI
2
KPI-P2:
2016 Q2 ACSI + 2016 Q3 ACSI
2
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2015 Satisfaction: Member Interaction
if i
b
i
Silver
Gold
Platinum
Weighting
≥8.64
≥8.74
≥8.84
10%
Measures member “reviews” of new service, outage, walk‐in and contact center experiences; calculated by averaging two quarterly scores and rounding
d
d
Score reported as of October 31 2015
October 31, 2015 8 55
8.55
No Ranking
2016 Recommendation: Satisfaction ‐Interaction Measurement
Silver
Gold
Platinum
Weighting
Member Interaction Scores
≥8.64
≥8.74
≥8.84
5%
•Maintain
Maintain Member Interaction measure as it measures PEC
Member Interaction measure as it measures PEC’ss direct interaction with members on new service, direct interaction with members on new service,
outage, call center and walk‐ins. •Keep metrics (silver, gold, platinum) consistent with 2015 levels as they represent strong goals for PEC performance.
• PEC is currently under the Silver level (8.55/‐0.09)
• The 3Q TSE benchmark average is 8.75
• PEC’s past performance indicates that we can achieve higher levels, we will need to have consistently
higher performance in the future to do so.
Interaction Score = TSE: New Service + Outage + Call Center + Walk-in
4
KPI-P1:
2015 Q4 + 2016 Q1 Interaction Scores
2
KPI-P2:
2
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Minutes Acceptance:
BOD JHewa Minutes
12_17_2015_Final
of Dec 17, 2perpg
2015 9:00
(RES-2015-102
10.B.2.a
4.A
10.B.2.a
4.A
Silver
Gold
Platinum
Weighting
Third Place
Second Place
First Place
10%
Minutes Acceptance:
BOD JHewa Minutes
12_17_2015_Final
of Dec 17, 2perpg
2015 9:00
(RES-2015-102
2015 Fi
2015 Financial: Low Cost Provider
i l L
C t P id
M
Measures PEC PEC
residential rate in comparison to other co‐ops purchasing power
purchasing power from LCRA
Score reported as p
of October 15, 2015 3rd
d
Silver
(Est. First at end 2015)
2016 Recommendation: Low Cost
Measurement
Silver
Low Cost
Second place LCRA Coop/top 45% of lowest state wide co‐op providers
Gold
Second place LCRA Coop/top 35% of lowest state wide co‐op providers
Platinum
First place LCRA Coop/top 25% of lowest state wide co‐op providers
Weighting
10%
• Recommendation/Rationale
• PEC has demonstrated its ability to compete among LCRA Co‐ops, continue to maintain position
• PEC should begin to compare itself state wide co‐ops in order to move PEC h ld b i
i lf
id
i
d
towards the goal ranking within the top 10% (lowest)
• As of June 2015, PEC ($116.20) was just below the state wide co‐op average of $116.71
g
$
• Proposed Calculation
• Average price paid for residential service measured at 1,000 kWh
• Place ranking determined by PEC position compared with current LCRA Place ranking determined by PEC position compared with current LCRA
Co‐ops
• Percentile ranking (%) based on state‐wide survey completed twice a year
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10.B.2.a
4.A
Silver
Gold
Platinum
Weighting
≤ $400
≤ $390
≤ $385
10%
Minutes Acceptance:
BOD JHewa Minutes
12_17_2015_Final
of Dec 17, 2perpg
2015 9:00
(RES-2015-102
2015 Fi
2015 Financial: KPI‐P2 Controllable Costs
i l KPI P2 C t ll bl C t
Measures controllable costs per meter Projected Controllable Costs at end KPI P2
Projected Controllable Costs at end KPI‐P2
Score reported as of October 31, 2015 $
$380 Platinum
(est. $389 at end 2015)
2016 Recommendation: 2016
R
d ti
Controllable Costs Per Meter
Measurement
Silver
Gold
Total Controllable Costs Per Meter
KPI-P1
≤ $195
KPI-P2
≤ $390
KPI-P1
≤ $193
KPI-P2
≤ $385
Platinum Weighting
KPI-P1
≤ $190
KPI-P2
≤ $380
10%
The controllable costs per meter monitors those expenses over which the p
p
Cooperative has the most discretionary control. Controllable expense categories include distribution operations, distribution maintenance, consumer accounts, consumer service and information, economic development, and administrative and general costs. It does not include any impact from current or prior year KPI g
y p
p
y
payments. Our 2016 budget sets a controllable cost per meter at $387.
Total Controllable Expenses
Average Number of Meters/Month
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69
10.B.2.a
4.A
Silver
Gold
Platinum
Weighting
≥ 355
≥ 360
≥ 365
10%
Minutes Acceptance:
BOD JHewa Minutes
12_17_2015_Final
of Dec 17, 2perpg
2015 9:00
(RES-2015-102
2015 Fi
2015 Financial: Meters/Employee (KPI‐P2)
i l M t /E l
(KPI P2)
Measures meters per employee to encourage resource/process resource/process
efficiencies
p
Score reported as of October 31, 2015 386
Pl ti
Platinum
2016 Recommendation: Meters/Employee
Measurement
Silver
Gold
Average Meters per Employee
KPI-P1
≥ 382
KPI-P2
≥ 385
KPI-P1
≥ 387
KPI-P2
≥ 390
Platinum Weighting
KPI-P1
≥ 392
KPI-P2
≥ 395
10%
PEC’s 2016 budget is calculated based upon 725 full time employees ’
b d
l l db d
f ll
l
and would result in 386 average consumers per employee if PEC adds a typical number of meters in 2016.
Average Total Full-Time Equivalent Employees/Month
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70
2016 Recommendation: Cost Reduction in
2016
Recommendation: Cost Reduction in Transmission and Transmission and
Peak Power Expenses
“Demand Management”
Measurement
Silver
Gold
Transmission and Peak Power Cost Reduction
Greater than 2% of
actual 4CP reduction realized through active and deemed demand reduction
Greater than 3% of
actual 4CP reduction realized through active and deemed demand reduction
Platinum
Greater than 4% of actual 4CP reduction realized through active
and deemed demand reduction
Weighting
5%
• Recommendation/Rationale
• Transmission Cost of Service (TCOS) has increased 89% from 2010
• TCOS reduction through 4CP reduction is necessary to mitigate and reduce member costs and rates
TCOS d ti th
h 4CP d ti i
t
iti t
d d
b
t
d t
• 2015 PEC programs reduced 4CP by an estimated 7.06 MWs
• Estimated 2015 4CP savings would be a 0.57%
• Goal seeks to achieve 2‐5% savings
• Proposed Calculation
• Active and deemed demand reductions due to PEC programs are tracked
• The percentage reduction in 4CP is calculated
The reduction percentage is determined in the Fall following the 4CP period
• The reduction percentage is determined in the Fall following the 4CP period
• The same result is used for both December of the current year and June of the following year
2015 Fi
2015 Financial: Uncollectible Accounts
i l U ll tibl A
t
Silver
Gold
Platinum
Weighting
≤ 0.24%
≤ 0.20%
≤0.16%
10%
Measures “bad debt” written off as a percentage of operating revenue
operating revenue
Score reported as of October 31, ,
2015 0 03%
0.03%
Platinum
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71
Minutes Acceptance:
BOD JHewa Minutes
12_17_2015_Final
of Dec 17, 2perpg
2015 9:00
(RES-2015-102
10.B.2.a
4.A
Minutes Acceptance:
BOD JHewa Minutes
12_17_2015_Final
of Dec 17, 2perpg
2015 9:00
(RES-2015-102
10.B.2.a
4.A
2016 Recommendation: Uncollectible Accounts
Measurement
Silver
Gold
Platinum
Weighting
g
g
Uncollectible Accounts Written off as Percentage of Operating Revenue
≤ 0.20%
≤ 0.15%
≤0.10%
5%
• PEC has consistently out‐performed the industry over the last several years without overly‐aggressive policies and without impacting customer service.
• The NISC platform will allow PEC to continue policies and maintain performance, but cautions against lowering metric too aggressively and f
b t
ti
i tl
i
ti t
i l
d
affecting other KPI targets in customer satisfaction.
• A Platinum target of 0.10% will push staff for continued efforts and allow a safeguard for periods of non‐collection activity during high and low temperatures.
Amounts Written Off (12 mo. rolling)
Operating Revenue (12 mo. rolling)
2015 Fi
2015 Financial: Overtime Hours
i l O ti
H
Silver
Gold
Platinum
Weighting
≤ 5.25%
≤ 4.75%
≤ 3.75%
10%
Measures applicable overtime hours as %age of total
%age of total hours worked
p
Score reported as of June 30, 2015 4 08%
4.08%
Gold
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72
Minutes Acceptance:
BOD JHewa Minutes
12_17_2015_Final
of Dec 17, 2perpg
2015 9:00
(RES-2015-102
10.B.2.a
4.A
2016 Recommendation: Overtime Hours
Measurement
Silver
Gold
Platinum
Weighting
Overtime Hours as a Percentage of Total Hours Worked
≤ 4.50%
≤ 4.00%
≤ 3.50%
5%
• The 2016 budget is based on an overtime rate of 4.6%.
•A Gold performance would represent an estimated 30,160 hours of overtime per KPI period.
Total Overtime Hours
Total Hours Worked
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73
10.B.2.a
4.A
KPI Historical Results 2013 Results
2013 Results
2014 Results
2014 Results
TCIR
None‐3.43
None‐2.76
Gold‐2.10
+ Platinum‐1.46
DART
None‐2.51
None‐1.74
None‐1.80 + Silver‐0.88
SAIDI
Gold‐0.84/50.7 m
None‐1.04/62 m
Platinum‐0.8/48 m
Member Satisfaction
Silver‐80
Silver‐80
Silver‐80
Member Interaction
Silver‐8.64
None‐8.63
None‐8.59
+ Silver‐8.64
None‐$420.09
Platinum‐$397
None‐$426
+ Platinum‐$191
Platinum‐0.16%
Platinum‐0.09%
Platinum‐0.11%
None‐5.2%
None‐5.76%
Gold‐3.81%
= Platinum‐0.03%
+ Platinum‐3.43%
Platinum‐335
Platinum‐341
Platinum‐351
Lowest Cost Provider
N/A
N/A
N/A
*1% Adder Achieved
1/2 Adders
2/2 Adders
1/2 Adders
3.4%
4.0%
4.4%
Controllable Costs/Meter*
Uncollectible Accounts
Overtime Percentage
Meters per Employee*
Tho
ough
hts
Distribution
Comments
2015 KPI‐P1
2015 KPI
P1
Minutes Acceptance:
BOD JHewa Minutes
12_17_2015_Final
of Dec 17, 2perpg
2015 9:00
(RES-2015-102
2012 Results
‐ None‐34.6 min
= Silver‐80
= Platinum‐371
Platinum‐1st
+ 2/2 Adders
5.6%
Questions
Eng
gage
KPI Metric
KPI Metric
Participate
p
Discussion
Packet Pg. 77
74
Attachment: 2016 KPIMinutes
Plan_Final
Acceptance:
(RES-2015-102
Minutes: 2016
of Dec
Key
17,Performance
2015 9:00 AMIndicator
(Minutes
Plan
Approval)
and Methodology -M Racis)
10.B.2.b
4.A
Packet Pg. 78
75
2016 Key Performance Indicator Plan Purpose and Objectives
The purpose of the Key Performance Indicators (KPIs) is to provide an objective method for evaluating PEC’s business
performance and calculating performance-based financial distributions for eligible employees who contribute to the
advancement of the goals and initiatives outlined in the Cooperative’s approved Strategic Plan.
2016 KPI Plan Year
The plan year coincides with the calendar year (January 1, 2016 to December 31, 2016) to align with the Cooperative’s
current fiscal year, annual work plan process, and standard industry reporting required by the National Rural Utilities
Cooperative Financial Corporation and Occupational Safety and Health Administration (OSHA). A biannual KPI distribution
of equal periods will provide greater focus on Cooperative performance throughout the year. The first measurement period
(KPI-P1) will be January 1 to June 30, 2016 and the second measurement period (KPI-P2) will be July 1 to December 31,
2016. Accordingly, each biannual KPI calculation will be based on the most current scores and latest financial information
available at the close of the period. The distribution of KPI-P2 will be made prior to March 15, 2017. Each performancebased financial distribution will be based on the achievement of the 2016 calendar-year targets outlined in this plan and
approved by the Board of Directors by resolution on December17, 2015. Updates to the KPI Plan may be presented to and
approved by the Board throughout the plan year as reporting methodology is refined to align with unforeseen industry,
software, or other business transitions.
Employee Eligibility Requirements
The distribution percentage would be applied to total wages, which includes base pay, overtime and double time that were
paid for each of the equal measurement periods (KPI-P1 and KPI-P2). To be eligible for a KPI distribution for a particular
measurement period, an employee must meet each of the following requirements:



Have received an individual overall performance rating of meets expectations or above during the most recent
Cooperative-wide evaluation process if they were a PEC employee at that time
Have worked any time during the KPI measurement period, and
Be employed by PEC on the day the KPI is distributed
Packet Pg. 79
76
Plan_Final
Acceptance:
(RES-2015-102
Minutes: 2016
of Dec
Key
17,Performance
(Minutes
Plan
Approval)
10.B.2.b
4.A
2016 KPI Plan Safety Measurements
Measurement
Silver
Gold
Platinum
Weighting
Total Case Incident Rate (TCIR)
≤ 1.5
≤ 1.2
≤ 1.0
10%
Definition and Calculations for Total Case Incident Rate (TCIR):
Total Case Incident Rate (TCIR) is defined as the total number of OSHA-recordable injuries/illnesses (collectively called
“incidents”) that occurred throughout the Cooperative during the applicable KPI measurement period. This measurement is
only affected by recordable incidents in which an injury or illness actually occurred, and is not affected by other safetyrelated reports that do not involve an actual injury or illness. The total hours worked component consists of all hours worked
for non-exempt employees, including over time, double time and call out. For exempt employees, this measurement is
calculated using the standard 40 hours per week and is not reflective of the actual hours worked. This indicator is calculated
using the following formula and will be carried out one decimal place:
Total Number of OSHA Recordable Injuries/Illnesses X 200,000
Total Hours Worked
Measurement
Silver
Gold
Platinum
Weighting
Days Away Restricted Duty
(DART)
≤ 0.89
≤ 0.59
≤ 0.30
10%
Definition and Calculations for Days Away Restricted Duty (DART):
Days Away Restricted Time (DART) is defined as the total number of lost time and restricted duty injuries that occur
throughout the Cooperative during the applicable KPI measurement period. This measure is only affected by recordable
incidences in which an actual injury results in lost time or restricted duty. The total hours worked component consists of all
hours worked for non-exempt employees, including over time, double time and call out. For exempt employees, this
measurement is calculated using the standard 40 hours per week and is not reflective of the actual hours worked. This
indicator is calculated using the following formula and will be carried out to two decimal places:
Total Number of Lost Time/Restricted Duty Injuries/Ilnesses X 200,000
Total Hours Worked
Packet Pg. 80
77
Plan_Final
Acceptance:
(RES-2015-102
Minutes: 2016
of Dec
Key
17,Performance
(Minutes
Plan
Approval)
10.B.2.b
4.A
2016 KPI Plan Reliability Measurement
Measurement
Silver
Gold
Platinum
System Average Interruption
Duration Index (SAIDI) calculated
excluding planned, transmission,
and major weather events
KPI-P1
<33 minutes
KPI-P1
< 30 minutes
KPI-P1
< 27 minutes
KPI-P2
<66 minutes
KPI-P2
< 60 minutes
KPI-P2
< 54 minutes
Weighting
10%
Definition and Calculations for System Average Interruption Duration Index (SAIDI):
The System Average Interruption Duration Index (SAIDI) is an indicator of the Cooperative’s service reliability as measured
by its outage time during the applicable KPI measurement period. This index excludes planned, transmission, and major
weather outages. The basic calculation is as follows with the targets for KPI-P1 calculated for Jan. 1, 2016, to June 30,
2016; KPI-P2 will be based on Jan. 1, 2015 to Dec. 31, 2016:
Sum of All Member Interruption Durations as Defined Above
Total Number of Meters Served
x 60
Packet Pg. 81
78
Plan_Final
Acceptance:
(RES-2015-102
Minutes: 2016
of Dec
Key
17,Performance
(Minutes
Plan
Approval)
10.B.2.b
4.A
2016 KPI Plan Member Satisfaction Measurements
Measurement
Silver
Gold
Platinum
Weighting
ACSI Satisfaction Score
≥80
≥82
≥84
10%
Definition and Calculations for the ACSI Satisfaction Score Reported in TSE Services Residential Member
Satisfaction Tracking Report:
The American Customer Satisfaction Index (ACSI) is an independent, cross-industry review of more than 200 leading companies
including cooperatives, municipalities, and IOUs. The ACSI weighted average is on a 100-point scale and designed to measure overall
customer satisfaction, member expectations, and actual performance in relation to the ideal utility. Because the ACSI is reported in
whole numbers, any calculation resulting in a decimal will be rounded to the nearest whole number. The final calculation for the first
measurement period (KPI-P1) of January 1 to June 30, 2016 will be:
2015 Q4 ACSI + 2016 Q1 ACSI
2
The final calculation for the second measurement period (KPI-P2) of July 1 to December 31, 2016 will be:
2016 Q2 ACSI + 2016 Q3 ACSI
2
Measurement
Silver
Gold
Platinum
Weighting
Member Interaction Scores
≥8.64
≥8.74
≥8.84
5%
Definition and Calculations for the Member Interaction Scores Calculated from TSE Services Residential Member
Satisfaction Tracking Report::
Each quarter the TSE Services Residential Member Satisfaction Tracking Survey Report compares PEC results to all cooperatives in
the benchmark study (currently more than 70 electric co-ops). Each quarter the unique overall PEC satisfaction score in the outage,
new service, call center and walk-in categories will be averaged for a single, interaction score carried two decimal places. The final
calculation for the first measurement period (KPI-P1) of January 1 to June 30, 2016 will be:
2
The final calculation for the second measurement period (KPI-P2) of July 1 to December 31, 2016 will be:
2
Packet Pg. 82
79
Plan_Final
Acceptance:
(RES-2015-102
Minutes: 2016
of Dec
Key
17,Performance
(Minutes
Plan
Approval)
10.B.2.b
4.A
2015 KPI Plan Financial Measurements
Measurement
Silver
Gold
Platinum
Weighting
Low Cost
Second Place
LCRA co-op/top
45% of lowest
state wide co-op
providers
Second Place
LCRA co-op/ top
35% of lowest
state wide co-op
providers
First Place LCRA
co-op/ top 25% of
lowest state wide
co-op providers
10%
Definition and Calculations for Low Cost Electric Provider:
This indicator will be based on the average monthly price paid for residential service measured at 1,000 kWh by PEC
members compared with what members pay at other LCRA electric cooperatives and all state wide electric cooperatives.
State wide electric cooperative information is delayed so the indicate ranking will be based on the measurement from the
prior period. In other words, June will be based on the prior December measurement and December will be based on the
prior June measurement.
Packet Pg. 83
80
Plan_Final
Acceptance:
(RES-2015-102
Minutes: 2016
of Dec
Key
17,Performance
(Minutes
Plan
Approval)
10.B.2.b
4.A
Measurement
Total Controllable Costs per
Meter
Silver
Gold
Platinum
KPI-P1
≤ $195
KPI-P1
≤ $193
KPI-P1
≤ $190
KPI-P2
≤ $390
KPI-P2
≤ $385
KPI-P2
≤ $380
Weighting
10%
Definition and Calculations for Reportable Total Controllable Costs per Meter:
The controllable costs per meter monitors those expenses over which the Cooperative has the most discretionary control.
Controllable expense categories include distribution operations, distribution maintenance, consumer accounts, consumer
service and information, economic development, and administrative and general costs. It does not include any impact from
current or prior year KPI payments. This indicator is calculated for each of the measurement periods using the following
formula and will be rounded to the nearest whole dollar. The targets for KPI-P1 will be calculated for Jan. 1, 2016, to June
30, 2016; KPI-P2 will be based on .Jan. 1, 2016 to Dec. 31, 2016:
Total Controllable Expenses
Measurement
Silver
Gold
Platinum
KPI-P1
≥ 382
KPI-P1
≥ 387
KPI-P1
≥ 392
KPI-P2
≥ 385
KPI-P2
≥ 390
KPI-P2
≥ 395
Weighting
10%
Definition and Calculations for Average Meters per Employee:
This indicator measures the average number of meters in relation to the Cooperative’s full-time employee count to
encourage process efficiencies and proper management of employee resources. This indicator is calculated using the
following formula and will be rounded to the nearest whole number. The targets for KPI-P1 will be calculated for Jan. 1,
2016, to June 30, 2016; KPI-P2 will be based on Jan. 1, 2016 to Dec. 31, 2016:
Average Total Full-Time Equivalent Employees/Month
Packet Pg. 84
81
Plan_Final
Acceptance:
(RES-2015-102
Minutes: 2016
of Dec
Key
17,Performance
(Minutes
Plan
Approval)
10.B.2.b
4.A
Measurement
Silver
Gold
Platinum
Weighting
Transmission and Peak Power
Cost Reduction
Greater than 2%
of actual 4CP
reduction realized
through active
and deemed
demand reduction
Greater than 3%
of actual 4CP
reduction realized
through active
and deemed
demand reduction
Greater than 4%
of actual 4CP
reduction realized
through active
and deemed
demand reduction
5%
Definition and Calculations for Transmission and Peak Power Cost Reduction:
This indicator will be based on the calculated annual, average percentage 4CP (4 Coincident Peaks for June, July, August,
and September) reduction as determined by PEC’s active and passive demand management programs and incentives and
the ERCOT 4CP Transmission Cost of Service allocation methodology. Each year during the 4CP months PEC will
determine the deemed demand savings by summing the total of actual active demand reductions and the calculated
demand reductions realized through passive programs. The measured score will be determined in the Fall of each year and
remain in effect for two-sixth month periods and recorded in December and June.
ERCOT (MW)
PEC (MW)
6/10@4:45 7/30@4:45 8/10@5:00 9/08@4:30
Average
61,679.0 67,679.0 69,830.0 64,478.0 65,916.5
1,104.0 1,276.0 1,366.0 1,203.0 1,237.3
Active Demand Reduction (MW)
Deemed Demand Reduction (MW)
0.0
8.0
9.0
8.0
6.25
0.70
0.75
0.81
0.81
0.77
Total (MW)
0.70
8.75
9.81
8.81
7.02
Adjusted Peak (MW)
% Peak Demand Reduction
1,104.70 1,284.75 1,375.81 1,211.81 1,244.27
0.06%
0.68%
0.71%
0.73%
0.56%
Packet Pg. 85
82
Plan_Final
Acceptance:
(RES-2015-102
Minutes: 2016
of Dec
Key
17,Performance
(Minutes
Plan
Approval)
10.B.2.b
4.A
Measurement
Silver
Gold
Platinum
Weighting
Uncollectible Accounts Written off
as %age of Operating Revenue
≤ 0.20%
≤ 0.15%
≤0.10%
5%
Definition and Calculations for Uncollectible Accounts Written Off as Percentage of Operating Revenue:
This indicator measures the percentage of the Cooperative’s total electric billings that corresponds to member accounts that
cannot be collected and is commonly known as “bad debt.” This indicator is calculated on a 12 month rolling basis using the
following calculation and will be carried out to two decimal places:
Amounts Written Off (12 mo.rolling)
Operating Revenue (12 mo.rolling)
Measurement
Silver
Gold
Platinum
Weighting
Overtime Hours as a %age of
Total Hours Worked
≤ 4.50%
≤ 4.00%
≤ 3.50%
5%
Definition and Calculations for Overtime Hours as Percentage of Total Hours Worked:
This indicator compares the total amount of overtime to the total hours worked during the period to encourage process
efficiencies and proper management of employee resources. The total hours worked component consists of all hours
worked for non-exempt employees and does not include double time (call out). For exempt, non-990 reportable employees,
this measurement is calculated using the standard 40 hours per week and is not reflective of the actual hours worked. This
indicator is calculated using the following formula and will be carried out to two decimal places:
Total Overtime Hours
Total Hours Worked
Packet Pg. 86
83
Plan_Final
Acceptance:
(RES-2015-102
Minutes: 2016
of Dec
Key
17,Performance
(Minutes
Plan
Approval)
10.B.2.b
4.A
Summary of KPI Measures, Targets and Weights for Each Period of 2016 KPI Plan
Category
Measurement
Silver
Gold
Platinum
Weighting
Total Case Incident Rate (TCIR)
≤ 1.5
≤ 1.2
≤ 1.0
10%
Days Away Restricted Duty (DART)
≤ 0.89
≤ 0.59
≤ 0.30
10%
System Average Interruption Duration
Index (SAIDI) calculated excluding
planned, transmission, and major
weather events
KPI-P1
<33 minutes
KPI-P1
< 30 minutes
KPI-P1
< 27 minutes
KPI-P2
<66 minutes
KPI-P2
< 60 minutes
KPI-P2
< 54 minutes
≥80
≥82
≥84
10%
≥8.64
≥8.74
≥8.84
5%
Second place
LCRA Co-op/ top
35% of lowest state
wide co-op
providers
First place LCRA
Co-op/top 25% of
lowest state wide
co-op providers
KPI-P1
≤ $195
KPI-P1
≤ $193
KPI-P1
≤ $190
KPI-P2
≤ $390
KPI-P2
≤ $385
KPI-P2
≤ $380
KPI-P1
≥ 382
KPI-P1
≥ 387
KPI-P1
≥ 392
KPI-P2
≥ 385
KPI-P2
≥ 390
KPI-P2
≥ 395
Greater than 2% of
actual 4CP
reduction realized
through active and
deemed demand
reduction
Greater than 3% of
actual 4CP
reduction realized
through active and
deemed demand
reduction
Greater than 4% of
actual 4CP
reduction realized
through active and
deemed demand
reduction
5%
Uncollectible Accounts Written off as
Percentage of Operating Revenue
≤ 0.20%
≤ 0.15%
≤0.10%
5%
Overtime Hours as a %age of Total
Hours Worked
≤ 4.50%
≤ 4.00%
≤ 3.50%
5%
ACSI Satisfaction Score (as reported in
the TSE Services Residential Member
Satisfaction Tracking Survey Report)
Member Interaction Scores Calculated
from TSE Services Residential Member
Satisfaction Tracking Survey Report
Low Cost
Total Controllable Costs per Meter
Transmission and Peak Power Cost
Reduction
Second place
LCRA Co-op/top
45% of lowest state
wide co-op
providers
20%
10%
10%
10%
Packet Pg. 87
84
Plan_Final
Acceptance:
(RES-2015-102
Minutes: 2016
of Dec
Key
17,Performance
(Minutes
Plan
Approval)
10.B.2.b
4.A
Calculation of Biannual Distribution for 2016 KPI Plan
After the final results are calculated for each period, the KPI distribution percentage to be paid to eligible employees will be
determined by multiplying the performance level award value by the weighting of that indicator:
Performance Level Percentage x Measurement Weight=Measurement KPI Distribution
Any calculated results will be rounded as noted in the specific definition with 1-4 moving down the scale, 5-9 moving up. All
measurement results will be subtotaled to obtain the percentage of the KPI distribution and any applicable adder
contributions will be factored in. The value for each performance level and the adders during each period is:
Performance Level
KPI-P1
KPI-P2
Silver
4.0%
4.0%
Gold
6.0%
6.0%
Platinum
8.0%
8.0 %
Example for Illustrative Purposes Only:
PEC’s 2014 Q4 ACSI Score is reported as 79. PEC’s 2015 Q1 ACSI Score is reported at 82. The final calculation for the
first measurement period (KPI-P1) of January 1 to June 30, 2015 will be:
2014 Q4 ACSI + 2015 Q1 ACSI OR
2
79 + 82 = 80.5
2
Because the ACSI is reported in whole numbers, any calculation resulting in a decimal will be rounded to the nearest whole number,
which is reported as 81. Using the defined target, this is Silver Level performance for a measurement with a weight of 10% during
KPI-P1.
Performance Level %age x Measurement Weight=Measurement KPI Distribution
OR
4.0% x 10% = 0.4%
Packet Pg. 88
85
Plan_Final
Acceptance:
(RES-2015-102
Minutes: 2016
of Dec
Key
17,Performance
(Minutes
Plan
Approval)
10.B.2.b
4.A
10.B.3
4.A
Board of Directors
Meeting: 12/17/15 09:00 AM
PO Box 1
RESOLUTION 2015-103
DOC ID: 3303 A
Subject: 2016-2020 Vegetation Management MSAs for Distribution and Transmission
Vegetation Maintenance
Submitted By: Brad Hicks
Background:
PEC requires outside support for vegetation clearing from our electrical distribution system as
we seek to gain efficiency and improve productivity by securing centralized contractor support
for these activities.
PEC has completed the competitive bid process for the 2016-2020 vegetation management
program and selected the qualified vendors to work on the system over the next 5 years. The
centralized program and vendor awards will go into full effective January 1, 2016.
Expenditure of cooperative funds estimated in the amount of $8.3M which is currently included
in the Cooperative’s 2016 operating budget; expenditures of staff time estimated in the amount
of 0 hours (other than ordinary processing requirements).
Updated: 12/12/2015 8:53 PM by Sylvia A. Romero A
Packet Pg. 89
86
Page 1
Department: Engineering & Energy Innovations
10.B.3
4.A
Regular Meeting
December 17, 2015
RESOLUTION 2015-103
NOW THEREFORE BE IT RESOLVED BY THE BOARD OF DIRECTORS OF THE
COOPERATIVE, that the Vegetation Management contracts are awarded as discussed in
Executive Session; and
BE IT FURTHER RESOLVED that the funding for the vendor contracts not exceed the amount
as discussed in Executive Session; and
RESULT:
MOVER:
SECONDER:
AYES:
ABSENT:
ADOPTED [UNANIMOUS]
Chris Perry
Updated: 12/12/2015 8:53 PM by Sylvia A. Romero A
Packet Pg. 90
87
Page 2
2016-2020 Vegetation Management Master Service Agreements for
Distribution and Transmission Vegetation Maintenance - B Hicks
10.B.4
4.A
Board of Directors
Meeting: 12/17/15 09:00 AM
PO Box 1
RESOLUTION 2015-104
DOC ID: 3307
Subject: Authorization For Regulatory Action with Public Utility Commission of Texas
Regarding Service Area E
Submitted By: Wayne McKee
Background:
Under the Texas Utilities Code, the Cooperative shall serve every consumer within its
certificated service territory. A municipally-owned utility seeks to serve its facilities within the
Cooperative's service territory. The Cooperative has communicated its position to the
municipally-owned utility and now seeks to pursue regulatory action with the Public Utility
Commission of Texas regarding these service area encroachments.
Expenditures of staff time estimated in amount of at least 115 hours (other than ordinary
processing requirements).
ATTACHMENTS:

8B4 Service Area Encroachment 12-17-15 VERSION 3 [Read-Only] 2perpg (PDF)
Updated: 12/11/2015 4:29 PM by Don Ballard
Packet Pg. 91
88
Page 1
Department: Operations
10.B.4
4.A
Regular Meeting
December 17, 2015
RESOLUTION 2015-104
Authorization For Regulatory Action with Public Utility Commission of
Texas Regarding Service Area Encroachments - W McKee / A Hagen
NOW THEREFORE, BE IT RESOLVED BY THE BOARD OF DIRECTORS OF THE
COOPERATIVE, that the Cooperative take any such necessary regulatory action with the Public
Utility Commission of Texas regarding service area encroachments by a municipally-owned
utility in Williamson County, Texas; and
that Chief Executive Officer, or designee, is hereby authorized as a duly authorized officer or
agent of the Cooperative, for and in the name and on behalf of the Cooperative, to do any and
all acts deemed necessary or appropriate in the best interests of the Cooperative to implement
this resolution.
RESULT:
MOVER:
SECONDER:
AYES:
ABSENT:
ADOPTED [UNANIMOUS]
Chris Perry
Packet Pg. 92
89
Page 2
WHEREAS, by law, Pedernales Electric Cooperative, Inc. (The "Cooperative") serves every
consumer within its certificated territory;
Attachment: 8B4 Service Area Encroachment
Minutes Acceptance:
12-17-15 Minutes
VERSION
of3Dec
[Read-Only]
17, 2015 9:00
2perpg
AM (RES-2015-104
(Minutes Approval)
: Authorization For Regulatory Action
10.B.4.a
4.A
Authorization For Regulatory Action with
Public Utility Commission of Texas
Regarding Ser
Service
ice Area Encroachments
Board of Directors’
Regular
g
Meetingg
December 17, 2015
As of 12.16.15
Boundary Map
2
Packet Pg. 93
90
Georgetown Utilities Facilities in Territory
3
Georgetown U
G
Utilities
ili i F
Facilities
ili i iin
Territory
y
Minutes Acceptance:
12-17-15 Minutes
VERSION
of3Dec
[Read-Only]
17, 2015 9:00
2perpg
AM (RES-2015-104
(Minutes Approval)
10.B.4.a
4.A
4
Packet Pg. 94
91
Minutes Acceptance:
12-17-15 Minutes
VERSION
of3Dec
[Read-Only]
17, 2015 9:00
2perpg
AM (RES-2015-104
(Minutes Approval)
10.B.4.a
4.A
Timeline

September 28, 2015:
Georgetown Utility Systems (GUS)
notifies PEC that GUS will serve new
Service Center within PEC territory;
PEC requests appropriate approvals

November 10, 2015:
Cease and desist letter mailed to
GUS

December 17,, 2015:
Consideration of PEC Board to take
regulatory action at PUCT regarding all
existing service area encroachments and
proposed encroachments by GUS
5
Packet Pg. 95
92
10.B.5
4.A
Board of Directors
Meeting: 12/17/15 09:00 AM
PO Box 1
RESOLUTION 2015-105
DOC ID: 3311
Subject: Amendments to On-Bill Financing Loan Policy and Underwriting Guidelines
Background:
The Cooperative previously approved in September 2015 an on-bill financing program for
distributed renewable solar photovoltaic systems to be effective January 1, 2016 and wishes to
expand this program to include grid-tied battery storage systems. The Cooperative is updating
the Loan Policy and Underwriting Guidelines to include those systems and to also update the
repayment structure for the loans and other necessary changes.
Expenditure of Cooperative funds used for the administration of the On-Bill Financing Program
will be recovered through the program fees.
ATTACHMENTS:

12-17-15 loan policy re on bill financing version 2 ANH (3) Final
(PDF)
Packet Pg. 96
93
Page 1
10.B.5
4.A
Regular Meeting
December 17, 2015
RESOLUTION 2015-105
Amendments to On-Bill Financing Loan Policy and Underwriting
Guidelines - B Beavers
WHEREAS, the Cooperative wishes to expand this program to include grid-tied battery storage
systems;
NOW, THEREFORE, BE IT RESOLVED BY THE BOARD OF DIRECTORS OF THE
COOPERATIVE that the Cooperative approve amendments to its Loan Policy and Underwriting
Guidelines for the on-bill financing program as attached hereto;
BE IT FURTHER RESOLVED BY THE BOARD OF DIRECTORS OF THE COOPERATIVE
that the Chief Executive Officer, or his designee(s), is hereby authorized and directed to do any
and all such other things, and take such other actions, as the Chief Executive Officer, or his
designee(s), deems necessary or desirable in his reasonable discretion to effectuate these
resolutions.
RESULT:
MOVER:
SECONDER:
AYES:
ABSENT:
ADOPTED [UNANIMOUS]
Chris Perry
Packet Pg. 97
94
Page 2
WHEREAS, the Cooperative previously approved in September 2015 an on-bill financing
program for distributed renewable solar photovoltaic systems;
10.B.5.a
4.A
LOAN POLICY AND UNDERWRITING GUIDELINES
Approved: September 14, 2015
Revised: December 17, 2015
PEC attempts to comply with federal and state laws regarding extensions of credit to its members.
Members eligible for this financing program must meet creditworthiness standards including evaluation
of payment history and other criteria as described herein.
In addition, Members will be subject to loan application and credit score checks.
Terms of Loan:





No more than $20,000 for Grid Tied Distributed Energy Resource (DER) Systems, including
distributed renewable solar photovoltaic systems and grid tied battery storage systems installed
by a qualified vendor
Repayment of Loan – Ten years or less
Interest – No more than 10%
Residential and Commercial members are eligible
Contingent upon satisfactory installation of grid tied equipment by qualified vendor
Underwriting Guidelines:

For residential service, during the most recent 12 consecutive months of electric service
(i)
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.

For commercial service, during the most recent 24 consecutive months of electric service
(ii)
(ii)
(iii)


Member must own property in fee simple in which installation to occur.
Loans shall be secured by a fixture filing on the qualified equipment . Member shall provide
appropriate evidence of insurance. .
Eligible members including joint members must meet the following criteria:

Credit Score
Billing History with no more
then one late payment (Months)
600 - 649
650 - 699
≥ 700
24
18
12
Packet Pg. 98
95
Attachment: 12-17-15 loan policy reMinutes
on bill financing
Acceptance:
version
Minutes
2 ANH
of Dec
(3) Final
17, 2015
(RES-2015-105
9:00 AM (Minutes
: Amendments
Approval)
to On-Bill Financing Loan Policy and
12-17-15 version 1











Member annual income or revenues must be three times the loan amount
The DER must meet all PEC interconnection standards.
Financing of all grid tied DER systems is contingent on final approval of installation and
approved interconnection with PEC. .
All joint members must authorize appropriate loan documentation.
Only one loan per account until expiration of any existing loan with PEC
Credit check fee will be collected upon request for pre-approval
Application fee will be collected upon submission of the member's loan package application and
may be refunded if member signs up for automatic payment in connection with the loan.
If Member authorizes automatic payments through either the Credit Card Payment Plan or Bank
Draft Payment Plan, then the application fee may be refunded.
A filing fee will be collected upon execution of the loan dcoumentation and completion of the
filings.
An administration fee shall be collected as an adder to the interest rate of the loan
A late fee may be assessed after 10 days of payment due date; greater of five percent (5%) on
amount due or $7.50
Repayment Guidelines:

After approval of installation by PEC and closing the loan, Member's bill will then include a lineitem for repayment of the loan through monthly installments. Monthly payments by Member go
first to the cost of interest and principal of the loan then to the electric service bills.
Collection Standards

In case of any delinquencies, any payment by Member goes first to the costs of interest and
principal of the loan then to the electric service bills.
Fair Lending


Credit decisions shall be made without adverse discrimination on the basis of race, color, religion,
sex, national origin, marital status, age (provided the applicant is of legal age and has the capacity
to enter into a binding legal contract), receipt of public assistance, or good faith exercise of rights
under the Consumer Credit Protection Act or any other prohibited basis. PEC will not discourage
the completion or submission of an application for credit by any applicant on any of the
prohibited bases.
It is the intent of the PEC to comply with the requirements of the Equal Credit Opportunity Act
and the Fair Credit Reporting Act as they may apply to any credit program.
2
Packet Pg. 99
96
Attachment: 12-17-15 loan policy reMinutes
on bill financing
Acceptance:
version
Minutes
2 ANH
of Dec
(3) Final
17, 2015
(RES-2015-105
9:00 AM (Minutes
: Amendments
Approval)
to On-Bill Financing Loan Policy and
10.B.5.a
4.A
15.A
4.A
Board of Directors
Meeting: 12/17/15 09:00 AM
PO Box 1
RESOLUTION 2015-106
DOC ID: 3304
Subject: Distribution Poles - Blanket Purchasing Agreement
Background:
Pedernales Electric Cooperative, Inc. requires material purchases to support maintenance and
growth of our electrical distribution system. PEC seeks to gain efficiency and improve
productivity by securing a multi-year materials blanket purchasing agreement, generally 3-year
term with 2 optional 1 year extensions.
Specifically, the Board may consider authorizing a distribution Wood Poles Blanket Purchasing
Agreement for up to 5 years.
As discussed in Executive Session.
Packet
PacketPg.
Pg.100
97
Page 1
15.A
4.A
Regular Meeting
December 17, 2015
RESOLUTION 2015-106
Distribution Poles - Blanket Purchasing Agreement - B Hicks
BE IT FURTHER RESOLVED, that the amount of Wood Poles BPA not exceed $15,000,000;
and
BE IT FURTHER RESOLVED, that the term for the Wood Poles BPA not exceed a total of 5
years; and
BE IT FURTHER RESOLVED, that the Chief Executive Officer or his designee is authorized to
RESULT:
MOVER:
SECONDER:
AYES:
ABSENT:
ADOPTED [UNANIMOUS]
Cristi Clement, Paul Graf, Amy Lea SJ Akers, James Oakley
Emily Pataki, Kathryn Scanlon, Chris Perry
COOPERATIVE, that the Wood Poles Blanket Purchasing Agreement (“BPA”) is awarded as
discussed in Executive Session; and
Packet
PacketPg.
Pg.101
98
Page 2
15.B
4.A
Board of Directors
Meeting: 12/17/15 09:00 AM
PO Box 1
RESOLUTION 2015-101
DOC ID: 3278
Subject: 2016 Operating Budget & Capital Improvement Plan
Submitted By: Tracy Golden
Department: Financial Services
Background:
The Board may consider and adopt an Operating Budget and Capital Improvement Plan for
calendar year 2016.
Controllable Expenses of approximately $108 million and an additional expenditure of
approximately $186 million for CIP is provided for in the 2016 budget.
Packet
PacketPg.
Pg.102
99
Page 1
15.B
4.A
Regular Meeting
December 17, 2015
RESOLUTION 2015-101
2016 Operating Budget & Capital Improvement Plan - T Golden
BE IT FURTHER RESOLVED that the Cooperative adopt the Operating Budget as presented
for calendar year 2016; and
BE IT FURTHER RESOLVED that the Chief Executive Officer or designee is authorized to take
such actions as needed to implement this resolution.
RESULT:
MOVER:
SECONDER:
AYES:
ABSENT:
ADOPTED [UNANIMOUS]
Clement, Pataki, Graf, SJ Akers, Oakley
Kathryn Scanlon, Chris Perry
BE IT RESOLVED BY THE BOARD OF DIRECTORS OF THE COOPERATIVE that the
Cooperative adopt the Capital Improvement Plan as presented for calendar year 2016; and
Packet Pg. 103
100
Page 2
5.A.1
Board of Directors
Meeting: 01/19/16 09:00 AM
PO Box 1
RESOLUTION (ID # 3331)
DOC ID: 3331
Subject: Director Travel Expense Policy Amendments
Submitted By: Don Ballard
Background:
The Board originally adopted a travel expense policy in 2008 and last amended it in June 2014.
The Board wishes to institute yearly allocations for directors for travel for business-related
conferences, seminars or training. The Board wishes to consider a $5,000 allocation for travel
per Board member; this amount reflects an estimate of the costs associated with attending 1
national conference (4 days) and 1 state conference (3 days).
Expenditure of Cooperative funds estimated in the amount of $35,000 currently included in the
Cooperative's 2016 operating budget; expenditures of staff time estimated in amount of 40
hours (other than ordinary processing requirements).
ATTACHMENTS:

Director Travel Expenses 01-14-2016 FINAL DRAFT (PDF)

Annual Calendar Schedule 2016
(PDF)
Updated: 1/15/2016 2:08 PM by Aisha N Hagen
Packet Pg. 104
Page 1
5.A.1
Regular Meeting
January 19, 2016
Director Travel Expense Policy Amendments
BE IT RESOLVED BY THE BOARD OF DIRECTORS (the "Board") of Pedernales Electric
Cooperative, Inc. (the "Cooperative") that the proposed amendment to the Cooperative's
Director Travel Expense Policy that was presented to the Board this day is hereby approved,
with such changes thereto as may have been made by the Board during the meeting; and
BE IT FURTHER RESOLVED that the Chief Executive Officer, or his designees, are hereby
authorized and directed to take all such action as may be necessary or desirable to effectuate
this resolution.
Packet Pg. 105
Page 2
5.A.1.a
Board of Directors Travel & Expense Reimbursement
Policy
1. Purpose:
This Board of Directors’ Travel and Expense Reimbursement Policy addresses how
and when members of the Board of Directors (“Directors”) are reimbursed with PEC
funds for travel and other expenses related to PEC business and meetings. PEC
requires certain qualifications related to educational and training certifications for
Directors. The Board is committed to Director education by seeking appropriate
opportunities to advance individual Director knowledge and skills in the electric
industry, risk management, and corporate oversight through participation and
service in related professional organizations, advanced training, attending state and
national association meetings, and gaining certifications or other accreditations.
2. Scope:
This Policy applies to Directors. This Policy addresses Director business travel and
expense reimbursement. Directors are not provided cash advances for travel or
conferences. This Policy does not address Director Compensation.
3. Definitions:
Approving Directors – means any 2 of the following, the Chair of the Audit
Committee; the Board President; the Board Vice-President; and the Board
Secretary/Treasurer.
Reimbursement – means the method by which PEC pays a Director for personal,
out-of-pocket expenses incurred for Board-approved business expenses, including
travel.
4. Policy Statement and Implementation:
Directors who use personal, out-of-pocket funds for PEC business travel or other
business-related expenses shall be reimbursed in accordance with this Policy.
a) Criteria For Reimbursement Approval
The Approving Directors, or the full Board when necessary, shall consider and
decide whether to approve any Director’s Reimbursement. Advance approval is
not required, but, when requested by the Director, may be sought. When
considering approval of a request, the following factors may be considered.
i) Business purpose of the expense or travel is valid and directly related to
official company business and service as a Director of PEC; and does not
include unrelated business, personal travel or companion travel expenses;
ii) Expenses are in accordance with this Policy, reasonable and necessary and
conform to any requirements imposed by the IRS and other regulatory
agencies as applicable; and
iii) All required accompanying documents are complete and accurate.
Attachment: Director Travel Expenses 01-14-2016 FINAL DRAFT (3331 : Director Travel Expense Policy Amendments)
PEDERNALES ELECTRIC COOPERATIVE, INC.
Policy ########
Page 1 of 7
Packet Pg. 106
b) Director Budget Allocation for Training or Conferences
i) Budget Allocation. Each calendar year, Directors are budgeted $5,000 for
the purposes of attending business-related conferences, seminars, training,
and education that are appropriate for service as a Director of PEC. The
Budget Allocation includes costs for registration, courses, travel, Per Diem,
and all reasonable and necessary costs associated with the event or
training.
ii) Reimbursement. Yearly Budget Allocations must be submitted for
Reimbursement under this Policy. Reimbursement shall be provided only for
expenses related to service as a Director and for the Board’s business
purpose. Advance approval is not required for use of the budged funds, but,
when requested by the Director, may be sought.
iii) Additional Budget Allocation. When a Director may or wishes to exceed their
yearly Budget Allocation, the Director shall seek advance approval from the
Board before any travel or expense. The Director’s request for additional
Budget Allocation will be considered and voted on by the entire Board.
iv) Exclusions. The yearly Budget Allocation does not include Reimbursement
related to PEC meetings or events within PEC’s service territory. The yearly
Director Budget Allocation does not apply to costs related to the Credentialed
Cooperative Director (“CCD”) designation that is required under PEC Bylaws
Article III, § 2(m).
c) Request, Review and Approval of Director Reimbursement
The following process shall be followed for Reimbursement
i) A director seeking Reimbursement for business expenses shall submit a
Director Payment Voucher, and any other forms and required receipts
within 30 days of the expense, final invoice, or completion of travel
ii) All Director Payment Vouchers shall be reviewed for approval by any two of
the following Directors, with no director permitted to review or approve their
own request: the Chair of the Audit Committee; the Board President; the
Board Vice-President; and the Board Secretary/Treasurer (“Approving
Directors”). When any two Approving Directors approve the expenses,
Reimbursement shall be paid through PEC Accounts Payable.
iii) If the Approving Directors are unwilling to approve a Reimbursement
request, or if the Approving Directors reject all or part of a request for a
Reimbursement, those Approving Directors must provide the requesting
Director with written justification for their action within three business days
after receipt of the request for Reimbursement. If the requesting Director
does not agree with the Approving Directors, then the requesting Director
may submit the request for Reimbursement to the entire Board for review
or withdraw the Reimbursement request. The entire Board will consider
5.A.1.a
Page 2 of 7
Packet Pg. 107
5.A.1.a
and vote on whether to approve or disapprove the Reimbursement request.
1. Date the expense was incurred.
2. The location where the expense was incurred (e.g., name of the hotel,
restaurant, city, business,).
3. The business purpose for the expense or travel, including the purpose
related to service as a Director; and the specific business reason for any
expense to which the business purpose does not apply.
4. The starting and ending points of travel for any automobile mileage
Reimbursement.
5. The names of all other people whose expenses are covered by the
request for a Reimbursement, including their relationship to the
Cooperative.
v) Any Director seeking Reimbursement shall obtain and provide an itemized
receipt for every expense for which a receipt is made available. If a receipt
is not issued or is lost, in lieu of the receipt, the Director shall affirm the
expenditure and provide a detailed explanation of the expense.
d) Other Reasonable and Necessary Expenses
i) Reasonable and necessary expenses meeting the Criteria for
Reimbursement Approval but not otherwise described by this Policy may
be reimbursed when documented and explained to the Board. The Board
grants the Approving Directors authority to approve any such
Reimbursement to cover reasonable and necessary expenses.
ii) Any director may request the entire Board to consider and review any
decision regarding a Reimbursement. The Board may affirm or reject the
decision of the Approving Directors.
iii) In measuring the reasonableness of expenses, the Board may consult the
per diem and hotel rates by location, updated each fiscal year by the U.S.
General
Services
Administration
and
available
at
http://www.gsa.gov/portal/category/21287.
iv) Specific Guidance for Travel
A. Lodging. Directors shall seek reasonable lodging based on the location
to which they may be traveling. Directors are encouraged to use the
Sales/Use Exemption form for lodging and other expenses within the
State of Texas.
B. When traveling to a conference, a director shall generally stay at the
hotel hosting the conference. Exceptions may be considered for the
following:
iv) Reimbursement requests with a Director Payment Voucher shall identify
the following information for each expense:
Page 3 of 7
Packet Pg. 108
5.A.1.a
Location (regional rates)
Lack of available rooms
Seasonal rate variations
Unexpected, last-minute reservations
C. A lodging receipt shall include the name and location of the lodging
establishment, dates of stay, and separate amounts for charges such as
lodging, telephone calls, meals and incidentals. Meals and incidentals on
lodging receipts must be itemized.
D. Directors shall be reimbursed for reasonable and actual expenses for
laundry services that are necessary due to an absence from home for 4
or more days or when unforeseen circumstances occur and are
explained in the trip documentation.
E. Directors shall be reimbursed for telephone, fax, and computer
connection costs that are reasonable and necessary for conducting
company business.
F. Air Travel. Directors shall purchase reasonably-priced tickets available
using a commercial discount airfare or customary standard (coach or
equivalent) airfare. Directors shall make timely reservations to secure
advance-purchase pricing. Other expenses such as upgrades, priority
boarding, preferred seating, or excess baggage are the responsibility of
the Director and are not eligible for reimbursement.
G. Rental Cars. Vehicle rental is authorized when it is more practical or
less expensive than the use of other transportation. Car-rental company
mileage charges are reimbursable, but Directors are not otherwise
provided a mileage allowance for distances driven in a rental car. The
cost of gas for a rental car is reimbursable. Directors shall accept the
insurance coverage offered by the rental car company. The director
shall follow the accident notification requirements of the rental car
company. If an accident occurs, the director shall notify the Legal
Services Department as soon as practicable, but no later than the
following business day.
H. Private Automobiles. PEC shall Reimburse Directors the standard
mileage allowance defined by the IRS for use of a private automobile,
based on the actual driving distance by the most direct route. Such
Reimbursement is made in lieu of any payment of actual automobile
expenses.
I. Meals and Incidentals. Either of the two options below may be selected
on a per trip basis for Reimbursement.
1. Actual Cost Option. Reasonable and necessary meal and incidental
expenses shall be reimbursed at actual cost. Incidental expenses
include fees and tips for persons providing services, such as food
•
•
•
•
Page 4 of 7
Packet Pg. 109
5.A.1.a
2. Per Diem Option. Per Diem rate when traveling to cover all meals
and incidentals on a daily basis. The Per Diem rate is based on the
US General Services Administration published Per Diem rates. Per
Diem rate covers breakfast, lunch, dinner, and incidental costs. To
cover meals and incidental costs incurred during travel days, the
specific travel day Per Diem rate will be applied. Travel Per Diem
rate will be determined by the published travel day rates of the U.S.
General
Services
Administration
and
available
at http://www.gsa.gov/portal/category/21287.
J. Combining Company and Personal Travel
If a Director takes an indirect route or interrupts a direct route for any
reason other than company business, the Cooperative shall reimburse
only for the portion required for business purposes. When the
Cooperative prepaid the airfare or rental car, the Director shall reimburse
the Cooperative for the PEC-unrelated portion of the expense.
Weekends, holidays or other necessary diversions or layovers shall be
eligible for Reimbursement when required for business or will result in
safer or more reliable or cost efficient travel.
e) Expenses that are Not Reimbursable
The following expenses are presumed not to be Reasonable or Necessary.
These expenses are not eligible for Reimbursement unless the Board makes
and enters into the minutes an affirmative determination that such an
expense is reasonable and necessary, including a description of the
circumstances and justification for that determination:
i.
ii.
iii.
iv.
v.
vi.
vii.
viii.
ix.
x.
xi.
xii.
xiii.
Alcohol
Child care
Dues in private clubs
Golfing or green fees
Gym and recreational fees, including massages and saunas
In-room movies and mini-bar charges
Life insurance, flight insurance, personal automobile insurance and
baggage insurance
Loss/theft of cash, airline tickets, personal funds or property
Lost baggage or excess baggage charge for personal items
"No-show" charges or penalties for flights, hotel and car service if
incurred due to non-business related changes in schedules
Parking or traffic fines
Personal automobile repairs, grooming services, shoe shines
Personal credit card annual fees or interest charges
servers, hotel housekeeping and luggage handlers, ground
transportation, and other reasonable and necessary expenditures,
including books, supplies, meeting expenses, parking, tolls, and cab
fares.
Page 5 of 7
Packet Pg. 110
xiv.
xv.
xvi.
xvii.
xviii.
xix.
xx.
Charges for personal telephone calls in excess of reasonable calls
Personal travel portion of a business trip
Pet care
Tips or service gratuities in excess of 20%
Unauthorized car rentals, registration fees, etc.
Discretionary upgrades (air, hotel, car, etc.)
Expenses of any person other than the Director, any other Director,
employee of the Cooperative, or other person when for a documented
and prudent business purpose.
5. Procedure Responsibilities
The Board implements this Policy. The Board and Approving Directors shall utilize a
Director Payment Voucher to document Reimbursements. The Approving Directors,
Legal Services, and Finance shall assist the Board in Reimbursement
responsibilities. Finance shall make payments through regular Accounts Payable
procedures.
Each calendar year, Legal Services and Finance shall report to the Board on
Director Reimbursements.
6. Enforcement
The Board of Directors enforces this Policy.
7. Superseding Effect
This Policy supersedes all previous policies and memoranda concerning the subject
matter. Only the Approver may authorize exceptions to this policy.
8. References and Related Documents:
Director Compensation Policy
Employee Expense Reimbursement & Travel Policy
Travel Policy
U.S. General Services Administration federal travel rates and policies available
at http://www.gsa.gov/portal/category/21287 (visited January 11, 2016)
5.A.1.a
Page 6 of 7
Packet Pg. 111
5.A.1.a
Policy Number:
Review Frequency:
Last Reviewed:
Date Adopted:
Effective Date:
Amendment Dates:
Director Expense & Travel Reimbursement
Policy
Approver:
Every 3 years
June 21, 2014
May 19, 2008
March 1, 2016
December 8, 2008, November 21, 2011,
May 21, 2012, June 18, 2012, August 19,
2013, June 21, 2014
Board of Directors
Applies to:
Board of Directors
Administrator:
Board of Directors, Legal Services,
Finance
This Policy supersedes all previous policies
and memoranda concerning the subject
matter. Only the Approver may authorize
exceptions to this policy.
Superseding Effect
Policy Title:
Page 7 of 7
Packet Pg. 112
DATE(S)
DESCRIPTION
January 11-13
TEC Directors Conference
January 11
PEC Special Board Mtg of the Committees
January 19
TIME
HOTEL/LOCATION
CITY/STATE
Westin Riverwalk
San Antonio, TX
9:00 AM
PEC Auditorium
Johnson City, TX
PEC Board Meeting
9:00 AM
PEC Auditorium
Johnson City, TX
February 22
PEC Board Meeting
9:00 AM
PEC Auditorium
Johnson City, TX
February 11-14
NRECA Pre-Meeting Director Training
Hilton New Orleans Riverside
New Orleans, LA
February 14-17
NRECA Annual Meeting
Ernest N. Morial Convention Center
New Orleans, LA
March 21
PEC Board Meeting
PEC Auditorium
Johnson City, TX
April 2-5
NRECA Directors Conference
JW Marriott Austin
Austin, TX
April 6-7
CoBank 2016 Southwest Customer Meeting
Hyatt Regency Lost Pines
Austin, TX
April 11-14
SEPA Utility Solar Conference
Grand Hyatt Denver
Denver, CO
April 18
PEC Board Meeting
May 1-3
NRECA Legislative Conference
May 16
PEC Board Meeting
June 5-8
9:00 AM
9:00 AM
Johnson City, TX
Hotel TBA
Washington, DC
PEC Auditorium
Johnson City, TX
CFC Forum
Washington State Convention Center
Seattle, WA
June 25-30
NRECA Summer School West
Snow King Resort
Jackson Hole, WY
June 18
PEC Annual Meeting
10:30 a.m.
Dripping Springs High School Performing Arts Center
Dripping Spring, TX
June 20
PEC Board Meeting
9:00 AM
PEC Auditorium
Johnson City, TX
July 11-13
SEPA National Town Meeting
Ronald Reagan Bldg & International Trade Center
Washington, DC
July 12-14
CoBank 2016 Energy Directors Conference
Broadmoor Hotel
Colorado Springs, CO
July 15-20
NRECA Summer School East
Sheraton Myrtle Beach Convention Center Hotel
Myrtle Beach, SC
July 18
PEC Board Meeting
PEC Auditorium
Johnson City, TX
July 31-Aug 3
TEC Annual Meeting
La Cantera
San Antonio
August 15
PEC Board Meeting
PEC Auditorium
Johnson City, TX
Aug 31 - Sept 2
CoBank 2016 Energy and Water Executive Forum
Broadmoor Hotel
Colorado Springs, CO
September 19
PEC Board Meeting
PEC Auditorium
Johnson City, TX
October 11
NRECA Director Education
Union Station Hotel by Double Tree
St. Louis, MO
October 12-13
NRECA Region VIII & X Meeting
Union Station Hotel by Double Tree
St. Louis, MO
9:00 AM
9:00 AM
9:00 AM
9:00 AM
Attachment: Annual Calendar Schedule 2016 (3331 : Director Travel Expense Policy Amendments)
5.A.1.b
2016 Board Schedule of Meetings and Conferences
1/12/2016
Packet Pg. 113
October 17
PEC Board Meeting
November 7-9
CFC IBES
November 21
PEC Board Meeting
December 2-7
NRECA Winter School for Directors
December 19
PEC Board Meeting
Coop Connect Location
Headquarters
Bertram
Canyon Lake
Cedar Park
Engineering
Junction
Kyle
Liberty Hill
Marble Falls
Oak Hill
9:00 AM
9:00 AM
9:00 AM
Time
11:20pm & 12:30pm
12 p.m.
12 p.m.
12 p.m.
12 p.m.
12 p.m.
12 p.m.
12 p.m.
12 p.m.
12 p.m.
PEC Auditorium
Johnson City, TX
Belmond Charleston Place Hotel
Charleston, SC
PEC Auditorium
Johnson City, TX
Gaylord Opryland Resort
Nashville, TN
PEC Auditorium
Johnson City, TX
Dates
Dates have not been sent for 2016
*****There may be additional SEPA events announced at a later date.*****
Attachment: Annual Calendar Schedule 2016 (3331 : Director Travel Expense Policy Amendments)
5.A.1.b
2016 Board Schedule of Meetings and Conferences
1/12/2016
Packet Pg. 114
5.B.1
Board of Directors
Meeting: 01/19/16 09:00 AM
PO Box 1
DOC ID: 3354
Subject: Proposed Amendment to Election Policy and Procedures Relating to Voter History
Information
Background:
The Board considered an amendment to the Election Policy and Procedures allowing for
release of voter history information to Board director candidates.
Expenditure of Cooperative funds estimated in the amount of $0 including the Cooperative’s
2016 operating budget; expenditures of staff time estimated in the amount of two (2) hours
(other than ordinary processing requirements).
ATTACHMENTS:

Proposed Amendment to Election Policy and Procedures
(PDF)
Packet Pg. 115
Page 1
5.B.1
Regular Meeting
January 19, 2016
Proposed Amendment to Election Policy and Procedures Relating to
Voter History Information
COOPERATIVE, the amendment to the Election Policy and Procedures at paragraph 7.12.1
regarding voter history information is approved and adopted by the Board; and
BE IT FURTHER RESOLVED that the Chief Executive Officer, or his designee, is authorized to
take such actions as needed to implement this resolution.
Packet Pg. 116
Page 2
Proposed Amendment to PEC Elections Policy & Procedures Relating to
Voter History Information
(Add new Section 7.12.1)
Candidates Access to Voting History.
After a Candidate has been duly qualified and approved to be listed on the ballot,
the Candidate may request and be provided a Voter History List that contains
only the names and mailing addresses of Members who voted in the election
immediately preceding the current Election (i.e., email address and/or telephone
number and other personal information is not to be provided). The Voter History
List shall not contain any information that could indicate or otherwise reveal any
selections made by the Member in the election (for example, for whom the
Member voted or how the Member voted on any question). To obtain the Voter
History List, a Candidate must request this information by contacting the PEC
Election Liaison. The candidate must affirm in a sworn, notarized affidavit to use
the list only as directly related to the PEC Board of Directors election and for no
other purpose.
Attachment: Proposed Amendment to Election Policy and Procedures (3354 : Proposed Amendment to Election Policy and Procedures
5.B.1.a
Packet Pg. 117
6.A
Board of Directors
Meeting: 01/19/16 09:00 AM
PO Box 1
DOC ID: 3346
Subject: 2016 Election Timeline Revisions
Submitted By: Aisha N Hagen
Background:
Dates on Board approved 2016 Election Timeline have been revised to coincide with scheduled
February Regular Board Meeting date of February 22, 2016.
Expenditure of Cooperative funds estimated in the amount of $0 currently included in the
Cooperative's 2016 operating budget; expenditures of staff time estimated in amount of 0 hours
ATTACHMENTS:

2016 Election Timeline FINALRevised 1-19-16
(PDF)
Packet Pg. 118
Page 1
6.A
Regular Meeting
January 19, 2016
2016 Election Timeline Revisions - D Richards
BE IT RESOLVED BY THE BOARD OF DIRECTORS that the 2016 Election Timeline with
revisions be approved as attached.
Packet Pg. 119
Page 2
6.A.1
Item
Annual Decision (Election Services
Contract)
Establish Annual Meeting Date and
Location
Section Party
Due Date
11/13/2015
Upon approval of the Election
Timeline
1/19/2016
None specified/continuing
1/19/2016
Meeting
1/19/2016
Meeting
1/19/2016
At least a week before the Regular
Board meeting 4 months prior to an
election
2/15/2016
Before the February Regular Board
Meeting (timeline reflects Board
packet deadline).
2/15/2016
6.2.1.6 BOD/QC
At the Regular Board meeting 4
months before an election
2/22/2016
Candidate
6.2.1.4
Applicants/BRS
At or before 5 p.m. on the last
business day falling 82 days or more
before the date of the Annual
Meeting
3/28/2016
GC/BOD
3.1
BOD
Present Election Timeline
3.2
GC
Communications plan presented to
the Board of Directors
7.3
Communications
Department
3.2
BOD
GC/Communicatio
ns/IT/Board
Conduct Internal Coordination
Recording
Meeting and Establish PEC Election
3.3
Secretary/Legal/M
Team
ember
Services/SBS
Retain Background Verifier
6.2.1.7 GC
Post and make available Ballot
BRS/Communicati
Materials and Nomination
6.2.1.1.1 ons/Member
Application
Services
Direct the General Counsel to
6.1
BOD
prepare proposed Non-Director
Election items
Send Quality Control steps to the
General Counsel
Board will appoint the Qualifications
and Elections Committee
Candidate Application to be
delivered to the Board Recording
Secretary at PEC Headquarters in
Johnson City
Qualifications and Elections
Committee Meeting Date
2015-2016
Deadline**
Board Meeting
Board Meeting
Meeting
At or before the January Regular
Board Meeting
Meeting
4.1
Director will submit to the Board
Recording Secretary the name of a
person or persons residing in the
Director’s District eligible and willing
to serve on the Qualifications and
Elections Committee
(Revised 1/19/16)
6.2.1.6 BOD/BRS
7.13
SBS/GC
QEC/OGC/BRS
Candidate
7.1, 7.6 Applicants/PEC
staff
Election withdrawal deadline for
Candidate
7.2
removal from Ballot
Applicants
Presentation and approval of
Qualifications and
6.2.1.9,
Candidate slate, Ballot, and any NonElections
6.2.1.10
Director Election items
Committee /GC
Candidate
Candidate Forum
7.5
Applicants/PEC
(Candidates video recording)
staff
Candidate Orientation and
Candidate photographs
1
2/17/2015
8/18/2015
1/11/2016
1/19/2016
4/12/2016
The week preceding the April
Regular Meeting of the Board
4/13/2016
Before Board approval of Ballot
4/18/2016
At least 2 months prior to an election
4/18/2016
On the Thursday after the Ballot is
approved by the Board
4/21/2016
Attachment: 2016 Election Timeline FINALRevised 1-19-16 (3346 : 2016 Election Timeline Revisions)
Packet Pg. 120
6.A.1
Item
Section Party
(Revised 1/19/16)
Due Date
2015-2016
Deadline**
Mailing of Ballots
7.4.1
SBS
Delivered between 25 and 30 days
before the Annual Meeting*
5/19/2016
Online voting site goes live
7.4.2
SBS
30 days before the Annual Meeting
5/19/2016
Initial voting email notifications
7.4.3
SBS
5/19/2016
Between 25 and 30 days before the
Annual Meeting
7.4.1
SBS/IT
5/26/2016
7.12
GC
7.12
GC
7.4.1
SBS/IT
Reminder voting emails
7.4.3
SBS
Update on Voter Turnout
7.12
GC
Deadline for mailing or webcasting
advance ballots
8.4
SBS
Eight days before Annual Meeting
6/10/2016
Record Date for Casting Ballot at
Annual Meeting, transmittal by PEC
of Members eligible to vote to SBS
5.2
IT
Close of business four business
days before Annual Meeting
6/14/2016
Pre-Annual Meeting Quality Control
7.14
SBS
Post-Tabulation, Pre-Announcement
Quality Control
8.8
SBS
Announcement and Certification
8.9
SBS
Post-Election Director
Acknowledgments
8.10
BOD
District-by-District Results
9.1
SBS
Post-Election Analysis
9.2
GC
mailed
Once weekly after Ballots are initially
mailed
Dates to be determined each year
when timeline presented to the
Board of Directors
mailed
At the close of the final business day
before the Annual Meeting
the meeting has concluded
Within five business days of the
Annual Meeting
Within two months after the Annual
Meeting
5/26/2016
6/2/2016
6/2/2016
5/26/2016
6/2/2016
6/9/2016
6/17/2016
6/18/2016
6/18/2016
6/18/2016
6/24/2016
8/18/2016
*Ballots are mailed for intended delivery to Members on the first day of voting period. It is anticipated that U.S. addresses will be
mailed 3 days in advance and international addresses 10-15 days in advance of the first day of voting.
**Dates listed here are subject to change due to aligning dates of the Board of Directors Meetings
2
Packet Pg. 121
6.A.1
3
Packet Pg. 122
6.A.1
4
Packet Pg. 123
6.C.1
1st Proposal (Absolute):
Amend Article II, Section 3, to read as follows:
Section 3. Open Meetings. A Member has the right to attend and speak at every regular,
special, or called meeting of the Board of Directors and its committees, except for executive
sessions as allowed by policy and law. All meetings shall be called with proper notice, and any
final action, decision, or vote on a matter shall be made in an open session.
2nd Proposal (With Limitations)
Amend Article II, Section 3, by adding a new, second paragraph as follows:
A Member has the right to speak at every regular meeting of the Board, and as otherwise
allowed by the board, pursuant to any Open Meetings and/or Decorum policy of the
Board.
3rd Proposal (Designated Times)
Amend Article II, Section 3, by adding a new second paragraph as follows:
The Board shall, from time to time, designate specific opportunities at its board meetings
in order to allow Members to address the Board, pursuant to any Open Meetings andor
Decorum policy of the Board.
Attachment: Proposed Amendment to PEC Articles of Incorporation (3348 : 2016 Election and Ballot Initiative Update - D Richards)
PROPOSED AMENDMENT TO PEC ARTICLES OF INCORPORATION
Packet Pg. 124
6.D
Board of Directors
Meeting: 01/19/16 09:00 AM
PO Box 1
DOC ID: 3325
Subject: Direct Outside General Counsel to Prepare 2016 Ballot Item(s) - D Richards
Background:
Section 6.1 of the Election Policy and Procedures provides that
"The Board may, from time-to-time, submit matters under consideration by the Board to a
vote of the Members. The vote in any such Non-Director Election shall be advisory only,
except in such cases where a vote of Members is required by law or the PEC Bylaws, such
as a vote to amend the PEC Articles of Incorporation. No later than the Regular Board
Meeting 5 months prior to an election, the Board will direct the General Counsel to prepare
proposed Ballot wording for any items to be put to a vote in a Non-Director Election. Any
such matters will be presented by the General Counsel in a way to enhance Member
understanding of such measures, including any Board recommendation or position
concerning such a vote."
The Board may now wish to consider whether any Non-Director elections items shall be placed
on the 2016 election ballot.
HISTORY:
01/11/16
Board of Directors
DEFERRED
Next: 01/19/16
Expenditure of Cooperative funds estimated in the amount of $0 currently included in the
Cooperative's 2016 operating budget; expenditures of staff time estimated in amount of 0 hours
Packet Pg. 125
Page 1
6.D
Regular Meeting
January 19, 2016
Direct Outside General Counsel to Prepare 2016 Ballot Item(s) - D
Richards
BE IT RESOLVED BY THE BOARD OF DIRECTORS OF THE COOPERATIVE that the
Outside General Counsel of the Cooperative is hereby directed to prepare proposed ballot
wording for consideration by the Board of Directors on the following Non-Director Election
(as defined in the Cooperative's Election Procedures) matter(s): _______; and
BE IT FURTHER RESOLVED that, in accordance with Section 6.1 of the Election
Procedures, the ballot wording will be presented in a way to maximize Members'
understanding of the Non-Director Election matter, including any Board recommendation or
position concerning the matter; and
BE IT FURTHER RESOLVED that the Board votes to [support/oppose] the proposed NonDirector Election matter and the Outside General Counsel is directed to draft proposed
ballot language that reflects the Board's position; and
BE IT FURTHER RESOLVED that this proposed Non-Director Election matter shall not be
included on the ballot unless and until a majority of the Directors votes to affirmatively place
the matter on the ballot and approves the ballot wording.
Packet Pg. 126
Page 2
7.A.2.a
January Corporate Services Board Report
Safety Department
Our First Aid, CPR/AED and Blood-Borne Pathogens training of PEC employees has come to a close
for 2015 with 546 employees receiving the training. This training, new for some employees and a
refresher for others is conducted biannually. A best practice first-aid program emphasizes having
someone who is trained in the delivery of initial medical emergency procedures, using a limited amount
of equipment to perform a primary assessment and intervention while awaiting arrival of emergency
medical services (EMS).
The Block and Tackle system was invented in Ancient Greece, circa 250 B.C by scientist and
mathematician Archimedes. Today various configurations of the original concept are used daily by our
field personnel. Trading force for distance the block and tackle system will, among many other uses,
raise and lower transformers, cross-arms and conductors. One of the most common configurations is
known as the handline and is extremely vital in a pole top, bucket truck or confined space rescue of an
injured employee.
A recent invention of a component followed by a modification to the “block” is changing our normal work
practices to be more efficient and safe efficient. However one of the biggest impacts of this new design,
known as the OX Block allows our lineworkers to perform a “rescue” in a shorter amount of time i.e. 2550% then with the traditional equipment.
Cody Jennings, a PEC Electrical Safety Instructor is conducting advanced specialized training to our
field workers to educate our employees on how to implement this in their everyday work. The training,
titled “Mechanical Advantage” teaches and reinforces knowledge of block and tackle concepts, leverage
and capstan hoist installation among other theories and application. This training, both classroom and
field application is scheduled for each district.
Our Pole Top Rescue training for 2015 was completed in December. The training is required annually for
employees working in the field and is basically a demonstration of proficiency of the skills a lineworker will
need to perform a rescue in the event of an emergency. A satisfactory performance requires a lineworker to
complete the task within 4-6 minutes. Our summary of 2015 revealed that 97% of the lineworkers are
proficient in Pole Top Rescue. Our instructors are coordinating one-on-one training sessions at each district
to assist the 3% that were timed outside of the 6 minute time-frame.
An Arc Flash Event from a short circuit can expel large amounts of deadly energy with temperatures in
excess of 35,000 degrees Fahrenheit. To further extend our safety equipment availability for use by our
employees that work in proximity to those hazards Arc Flash Face-shields are now issued.
Attachment: 2016 January CS safety report [Revision 2] (3330 : Corporate Services Report)
SAFETY ACCOMPLISHMENTS & TRAINING
Darrell Hall, a PEC Electrical Safety Instructor is conducting training on the OSHA regulations for the
use of this equipment. The training includes application, wear and maintenance requirements for those
employees to be issued the equipment.
Packet Pg. 127
7.A.2.a
Safety Department
SAFETY PERFORMANCE METRICS
The Safety Department monitors trends and responds to potential safety hazards in the workplace. The
two industry standards utilized to measure safety performance include:
•
TCIR = The Total Case Incident Rate calculated as:
Total number of recordable injuries/illnesses x 200,000 / man-hours worked
•
DART = Days Away Restricted Time calculated as:
Total number of injuries/illnesses that result in
Lost Time or Restricted Duty x 200,000 / man-hours worked
ü Total Man-hours worked in this YTD Period (01/01/2015 – 12/31/2015): 1,374,264.16
ü Total Man-hours worked in December: 130,984.24
ü ALL Recordable injuries/illnesses in this YTD Period (01/01/2015 – 12/31/2015): 9
*All Lost Time, Recordable Injuries, & Restricted Duty cases
We are pleased to report continued improvement with our TCIR and DART performance!
TCIR
TCIR ending KPI
TCIR ending
PEC’s TCIR Goal
Period 12/31/2014
12/31/2015
Total OSHA-recordable
injuries/illnesses
DART
Total lost time and restricted
duty injuries/illnesses
2.15
1.31
<2.7
DART ending
12/31/2014
DART ending
12/31/2015
PEC’s DART Goal
1.97
0.73
<1.0
December Safety Information - YTD
Number of Lost-time Injuries
*All Lost Time Accidents are OSHA Recordable
Other OSHA & Recordable Injuries
*All Recordable Injuries & Restricted Duty cases are OSHA Recordable
Number of Non-Recordable First Aid / Incident
This Month
Year to Date
This Month
Year to Date
This Month
Year to Date
2015
2014
0
2
1
7
1
8
1
4
2
8
0
6
A “Protective Grounding Principals” class was presented to the Systems Engineering group. Jim
Vaughn from Atkinson Power and Light presented this topic teaching both theory and application to the
attendees. A thorough understanding of this procedure is vital as it determines when power line and/or
substation equipment is safe to perform work upon. The presentation was customized to include more
content related to substation and transmission line scenarios.
Packet Pg. 128
7.A.2.a
Number of Vehicle Accidents
Number of Employees Trained
* Online & Instructor Led
Number of Training Sessions Held
*How many instructor led safety training sessions we provided
Class Attendance
*How many seats were filled throughout all Instructor led sessions
This Month
Year to Date
This Month
Year to Date
This Month
Year to Date
This Month
Year to Date
3
12
166
646
17
176
209
4,519
0
22
177
755
12
349
186
5,779
*current Learning Management System has not been receiving new hire updates since June 2015
December Statistics
Lost Time:
• None
OSHA Recordable Injuries:
• An employee was changing parts on a hydraulic hand tool when it activated, smashing the
employees finger.
Non-Recordable First Aid / Incident:
• A hydraulic hose failed internally creating a pin hole in the hose. When valve was opened for
the tool use the pressure of the fluid caused puncture in hand through employee’s leather
work gloves.
Vehicle Accidents:
• 2 incidents related to animal collision resulted in minor damage to PEC service vehicles.
• PEC service vehicle received minor damage as a result of collision with another vehicle.
Safety Department
Packet Pg. 129
Operations Update
January 19th, 2016
Wayne McKee
VP of Operations
Attachment: 0119_January_2016 Operations Update - December 2015 Activity (3340 :
7.A.3.a
Packet Pg. 130
• Monthly and Annual Operations Metrics








7.A.3.a
AGENDA
Reliability: SAIDI- System Average Interruption Duration Index
Reliability: SAIFI- System Average Interruption Frequency Index
Reliability: ASAI- Average Service Availability Index
System Growth: Line Extensions and Total Active Meters
Growth: Net Meter Count by District
Meter Growth: 2014/2015
Inventory: Material Issued
5 Year Materials Trend: Materials Issued by District
Packet Pg. 131
SAIDI - System Average Interruption Duration Index
2015 Final
63.2 min
Silver
SAIDI = (Restoration Time x Customers Interrupted) / Total Customers
7.A.3.a
Packet Pg. 132
7.A.3.a
SAIFI
Interruptions Excluding Planned, Transmission, ERCOT, Fire Marshall,
and Major Events
Events
2015 Final
.806 events
The System Average Interruption Frequency Index (SAIFI) is a system reliability measurement that shows
how often a customer experiences an outage during the time period. The SAIFI is calculated by dividing
the total number of customers interrupted by the total number of customers served.
SAIFI = Customers Interrupted / Total Customers Served
SAIFI - System Average Interruption Frequency Index
Packet Pg. 133
ASAI - Average Service Availability Index
The Average Service Availability Index (ASAI), also known as the Service Reliability Index, is the ratio of the total
number of customer hours that service was available during a given time period to total customer hours demanded.
This measurement represents system up-time.
ASAI =
Total Customer Hours Demanded – Customer Outage Time
Total Customer Hours Demanded
7.A.3.a
Packet Pg. 134
System Growth - Line Extensions / Meter Count
Exceeded
~275,000 meters
Total Active Meters
7.A.3.a
Packet Pg. 135
Growth - Net Meter Count by District
Total
Accounts
67,819
45,600
42,792
32,556
32,115
31,532
14,481
8,385
275,280
% of
Total
24.6%
16.6%
15.5%
11.8%
11.7%
11.5%
5.3%
3.0%
100%
Monthly
Growth
163
208
228
47
87
167
52
-2
950
% of Montlhy
Growth
17.2%
21.9%
24.0%
4.9%
9.2%
17.6%
5.5%
-0.2%
100%
As of December
31, 2015
Cedar Park
Oak Hill
Kyle
Marble Falls
Canyon Lake
Liberty Hill
Bertram
Junction
7.A.3.a
Top 3 Growth
In December
Packet Pg. 136
Meter Growth 2014-2015
7.A.3.a
Packet Pg. 137
Inventory
Material Issued
2015 Final: $35,877,138
2014 Final: $35,157,143
2014-2015 Material Comparison
7.A.3.a
Packet Pg. 138
5 Year Materials Trend
7.A.3.a
Packet Pg. 139
7.A.4.a
Engineering Summary Report
December 2015
Month
SAIDI (min)
SAIDI, Rolling 12 Month
Total (min)
SAIFI
CAIDI (min)
Jan
Feb
Mar
Apr
May
June
July
Aug
Sep
Oct
Nov
Dec
3.8
2.1
5.7
2.7
15.1
5.4
2.7
3.9
2.5
13.1
3.2
4.3
40.9
41.3
44.6
42.7
51.5
54.5
52.6
54.4
51.5
61.2
60.9
63.2
0.04
90.7
.03
77.7
.08
74.8
0.05
59.1
0.15
103.1
.09
62.4
.05
54.7
0.07
58.7
0.06
42.4
.08
157.2
.04
72.7
.08
53
2015 DISTRIBUTION IMPROVEMENT
PROJECTS
SUBSTATION CONSTRUCTION PROJECTS
In Design
T320 Hwy 32-Wimberley
Trading Post Breaker Add
Whitestone Tie Breaker
Raise T524 Buda Overpass
In Construction
Completed Projects
SJ Feeder Breaker
Glasscock Fdr Breaker
T327 Relocation
T523 Structure 8 Replacement
Fischer Tie Breaker Install
Nameless T1/T2 Upgrade
Antler T1/T2 Upgrade
T524/T466 OPGW DE Repl
Flatrock Substation Upgrade
Canyon T3 Addition
Goforth T1 Upgrade
Marshall Ford Breakers
Manchaca URD Repl
Kent St T2 Addition
Cranes Mill/Hwy32 PT
Design Pending
In Design
In Construction
YTD Completions
Cancelled
Total Projects
1
18
35
10
0
Rollovers/Multi-year
2015 New
32
64
32
Outages
Johnson City Cap Bank
Bertram T2 Addition
Purgatory Road Substation
SPCC Transformer Yard
Top Three Causes
Number of Outages
Members Affected
Scheduled
Equipment
Weather
231
4,046
121
10,285
84
3,043
For the month of December 2015 the outages affected in all 32,811 members.
The total outage time was 874 hours, with a member outage time of 31,010
hours.
Centex Breaker Repl
NEW LINE EXTENSIONS
Completed In
2012
2013
2014
2015
JANUARY
FEBRUARY
MARCH
APRIL
MAY
JUNE
JULY
AUGUST
354
432
605
571
404
600
662
643
397
906
713
716
497
771
907
1022
433
774
873
814
514
797
937
994
501
825
872
1080
469
799
939
892
SEPTEMBER OCTOBER
144
613
820
942
402
715
782
324
NOVEMBER
DECEMBER
YTD
357
639
627
445
381
615
586
663
4853
8486
9323
9106
Attachment: Engineering Summary Report (December) (3313 : Engineering and Energy Innovations Report - B Hicks)
RELIABILITY (Forced)
Packet Pg. 140
7.A.4.a
Pole Inspection Program
Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
Total Poles Inspected 2015 YTD
Total Poles Rejected 2015 YTD
Percentage of Poles Rejected
Reject Poles at Start of Month
Reject Poles Replaced/Repaired
Comments
8,589
15,316
21,165
26,988
34,267
34,267
37,013
44,833
49,748
53,956
64,013
69,524
302
465
663
761
989
989
1,093
1,291
1,539
1,794
2,610
2,994
3.5%
3.0%
3.1%
2.8%
2.9%
2.9%
3.0%
2.9%
3.1%
3.3%
4.1%
4.3%
4420
4171
3999
3927
4415
3530
3075
2979
3028
2817
3636
3866
124
249
172
186
150
885
455
397
143
208
285
154
Note
Osmose began the 2014 inspections in November with the goal of inspecting 114k by end of 2016. These numbers are affecting the Reject Poles at the Start of Month.
137 Poles were replaced in June by contractor, 3 in Cedar Park and 26 in Bertram replaced by the District crews, the remaining 719 poles were field identified by
Schneider Engineering as repaired/replaced and by extracting the pole prikey from UC on 6-26-15 to help me identify any straggler poles that were submitted to existing in
UC. 223 Poles were replaced in July and the remaining count were identified as replaced/repaired/removed by Schneider Engineering or replaced by the district as a
priority pole. 397 poles includes (223 C-truss, 7 priority and 164 backlog poles). No C-truss work was done this month but will continue in Octorber. (109 backlog poles
and 34 priority poles). 165 Poles replaced and 43 repaired in October. A total of 285 poles were repaired or replaced in the month of November. A total of 154 poles
were repaired or replaced in December.
ERCOT Control Center Activity
Advisory for Physical Responsive Capability < 3000 MW
Watch for Physical Responsive Capability < 2500 MW
Level 1 of Energy Emergency Alert (EEA) < 2300 MW
Level 2a of EEA < 1750 MW
Level 2b of EEA < 60 Hz
Level 3 of EEA < 59.8 Hz (Rolling Blackouts)
0
0
0
0
0
0
Unique Events
Completed annual equipment operational cycling at five [5] substations: Graphite Mine, Henly, Hwy 32, and Horseshoe Bay.
Substation crews completed 25KV breaker maintenance on eight [8] substation oil breakers.
Pike contractor performed maintenance on five [5] 138KV gas breakers.
Substation crews converted the Balcones T2 transformer to 25KV during the Cedar Park voltage conversion of BL-90. Switched all load back to normal after conversion.
Substation crews performed relay calibration on Bus Differential and Line Differential relays at Hwy 32.
Substation crew repaired hot spots on the capacitor banks at Leander and Lago Vista identified by infra red surveys.
Substation crews switched out and isolated T1 at Fischer for a construction project to add a total breaker, a tie breaker, and a transfer bus tie switch.
Substation crew assisted the Canyon district with permanently transferring part of FO-150's load to idle breaker FO-140 out of Fair Oaks substation.
Substation crew provided training to the Cedar Park district on using the automatic racking system on metal clad breakers in their district.
Attachment: Engineering Summary Report (December) (3313 : Engineering and Energy Innovations Report - B Hicks)
Engineering Summary Report
December 2015
Packet Pg. 141
CONFIDENTIAL/CLOSED ITEM
(Page 142-144)
7.A.4.c
The following table and graph indicates the Statistical Interruption Time per Meter
during a rolling 12 month period previous to and including the month indicated.
This is also referred to as the System Average Interruption Duration Index or SAIDI.
The number values represent Interruption Time in Minutes.
The two KPI periods are January 1 - June 30 and January 1 - December 31
Interruptions Exclude Planned, Transmission, Fire Marshall and Major Weather.
Year
2012
2013
2014
2015
Interruption SAIDI Excluding Planned, Transmission, Fire Marshall and Major Weather
Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
43.6
38.0
42.8
41.7
45.0
46.9
52.0
51.7
51.1
50.7
49.4
57.5
62.1
61.4
64.3
64.6
65.0
63.0
61.7
62.5
72.3
73.8
61.1
56.0
53.8
54.9
53.2
50.2
48.0
47.5
48.0
38.2
38.5
40.9
41.3
44.6
42.7
51.5
54.5
52.6
54.4
51.5
61.2
60.9
Dec
55.8
64.8
38.7
63.2
80.0
70.0
SAIDI (Minutes)
60.0
50.0
40.0
30.0
20.0
10.0
0.0
Jan
Feb
Mar
2012 SAIDI
Apr
May
Jun
2013 SAIDI
Jul
Aug
Sep
2014 SAIDI
Oct
Nov
Dec
2015 SAIDI
Note: 2015 Platinum is 27 minutes per meter from January 1 through June 30
Gold is 30 minutes per meter from January 1 through June 30
Silver is 33 minutes per meter from January 1 through June 30
Platinum is 54 minutes per meter from January 1 through December 31
Gold is 60 minutes per meter from January 1 through December 31
Silver is 66 minutes per meter from January 1 through December 31
Attachment: SAIDI Indicator for 2014-2015 (3313 : Engineering and Energy Innovations Report - B Hicks)
Rolling 12 Month SAIDI Reliability Indicator
Packet Pg. 145
Energy Usage and Average Temperature
Rolling 2 Year Comparison (Monthly)
700,000,000
100
PEC System Total kWh (non billing data)
600,000,000
90
550,000,000
500,000,000
80
450,000,000
400,000,000
70
350,000,000
300,000,000
60
250,000,000
200,000,000
50
150,000,000
100,000,000
50,000,000
40
Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Monthly KWH - 01/14 thru 12/14
Monthly KWH - 01/15 thru 12/15
Average Temperature - 01/14 thru 12/14
Average Temperature - 01/15 thru 12/15
Dec
Monthly Avg. Temp. Degrees F. (Johnson City)
650,000,000
Attachment: Temperature (monthly) December 2015 (3313 : Engineering and Energy Innovations Report -
7.A.4.d
Packet Pg. 146
12/28/15
12/14/15
11/30/15
11/16/15
140,000,000
11/2/15
10/19/15
10/5/15
9/21/15
9/7/15
8/24/15
Air Temp.
Air Temp.
PEC System kWh
120,000,000
100,000,000
Air Temp.
PEC System kWh
40,000,000
80
70
60
50
40
30
60,000,000
20
10
Avg Air Temperature degrees F. (Johnson City)
Weekly PEC System kWh (non billing data) vs Weekly Avg Air Temp
110
100
90
Attachment: Temperature (weekly) December 2015 (3313 : Engineering and Energy Innovations Report - B
Week Beginning With...
8/10/15
PEC System kWh
7/27/15
7/13/15
80,000,000
6/29/15
6/15/15
6/1/15
5/18/15
5/4/15
160,000,000
4/20/15
4/6/15
3/23/15
3/9/15
2/23/15
2/9/15
1/26/15
1/12/15
180,000,000
12/29/14
12/15/14
12/1/14
11/17/14
11/3/14
PEC System kWh (non billing data)
7.A.4.e
Packet Pg. 147
Engineering & Energy Innovations
Volt/VAR Optimization
- Update January 19, 2016
Bradley H. Hicks
Vice President, Engineering and Energy Innovations
Attachment: 2016_19_Jan_Volt Var Optimization Update (3313 : Engineering and Energy
7.A.4.f
Packet Pg. 148
Volt / VAR Optimization Pilot
• System is operating in monitor mode (receiving
voltage readings from Bellwether meters)
• OSI (SCADA Vendor) – performing system
configuration
• Revised go-live scheduled for February 15, 2016
• Detailed update April 2016
Attachment: 2016_19_Jan_Volt Var Optimization Update (3313 : Engineering and Energy
7.A.4.f
Packet Pg. 149
Power Supply and
Energy Services Update
January 2016
Ingmar Sterzing
V.P. Power Supply & Energy Services
Pedernales Electric Cooperative
Attachment: BOD Power Supply and Energy Services Rpt JAN16 BOD Meeting_v3 (3351 :
7.A.5.a
Packet Pg. 150
1
Power Supply Summary

PEC Peak Demand (Dec. & 2015)
–
967 MW on 12/28/15 @ 7:45 am
–
1,376 MW on 08/11/15 @ 6:00 pm
PEC 4CP
–



1,255.9 MW (1.90% of Total ERCOT)
PEC Energy Requirements (Dec. & 2015)
–
446,444 MWh (Dec.)
–
5,948,000 MWh (2015)
ERCOT LCRA Load Zone Real Time Price
ERCOT Winter Forecast
(Dec 2015 – Feb 2016)
 57,400 MW Peak Demand
 79,341 MW Total Generation
 7,817 MW Typical Gen Outages
 14,124 MW Operating Reserve
ERCOT Spring Forecast
Prelim. (Mar – May 2016)
 57,579 MW Peak Demand
 78,206 MW Total Generation
 8,591 MW Typical Gen Outages
 12,036 MW Operating Reserve
–
December: (0.73) Minimum - 17.10 Average - 589.49 Maximum $/MWh
–
ERCOT Dec. 2014 Average Real Time Price 26.01 $/MWh
–
2015: (36.35) Minimum - 24.31 Average - 1,538.66 Maximum $/MWh
–
ERCOT 2014 Average Real Time Price 41.03 $/MWh
Natural Gas Pricing
–
December: 1.63-2.39 $/MMBtu
–
2015: 1.63 – 3.32 $/MMBtu

7.A.5.a
Packet Pg. 151
2
 2015 Residential Rebates
– Total funds paid $405,375.00
– Number of units installed 1,260
– 811.81 KW Savings
– 2,749,316 kWh Savings
 2015 Commercial Rebate Program
– Commercial HVAC funds $97,991.38
– Commercial Lighting funds $127,496.00
– Total Commercial rebate: $225,487.38
 2015 Energy Audits
–
514 completed in 2015
Energy Services Summary
7.A.5.a
Packet Pg. 152
3
Member Services
December 2015
Prepared by
Eddie Dauterive
Attachment: December 2015 Member Services CEO Report Final (3337 : Member Services
7.A.6.a
Packet Pg. 153
Go Live Activity
Phone Volume
40,000
35,000
30,000
25,000
20,000
15,000
10,000
5,000
-
Nov 1
Dec 1
Jan 1
32,965
Typically 17,000 per week
16,768
100%
90%
80%
70%
60%
50%
40%
30%
20%
10%
0%
Wk Wk Wk Wk Wk Wk Wk Wk Wk Wk Wk Wk Wk Wk Wk
1
2
3
4
5
6
7
8
9 10 11 12 13 14 15
Call Volume
Monthly
Totals
Main Menu Options
Data thru 1/10/16
Typical Day
Direct to
Agent
37%
Eng.
2%
Secure Pay
33%
7.A.6.a
Indirect to
Agent
18%
Abandon
6%
Outage
5%
Service Level
• Service Level week-to-week impacted by
post-holiday high volumes
Oct.
Nov.
Dec.
Total
Call Volume
107,317
74,433
69,158
269,202
To Agents
61,395
39,837
36,304
75,579
To Secure
Pay
34,097
24,668
22,944
88,351
Service Level
8.6%
55.1%
52.9%
34.5%
Agent
Utilization
• Secure Pay has processed 56,635 payments
for over $9,385,000 since launch
96.1%
86.2%
82.9%
88.4%
Packet Pg. 154
• Utilization lowered toward goal, 82.9%
• 33% of members opt directly to Secure Pay
from the main menu
• 55% are transferred to agents by opting in
the menu or by not selecting any option
Go Live Activity
Service Level Analysis
Nov 1
40,000
35,000
30,000
25,000
20,000
Dec 1
• Daily Service Level has routinely been
32,965
over 90% over the last 2 months
Jan 1
100%
Similarly in week 13, another post
holiday peak impacted response times
• The dip in SL during week 9 occurred
after the holiday break, when contact
centers were unavailable for 4 days
• This short period of post-holiday
traffic greatly affected the weekly and
monthly metric
15,000
60%
50%
• Excluding these post-holiday peaks
16,768 in
volume, Service Level would have been40%
over 70%
30%
20%
• Capital credit inquiries also increased
volumes in December
5,000
80%
70%
• Agents are working to be fully
stabilized after this busy period
10,000
90%
-
10%
0%
Wk 1
Wk 2
Wk 3
Wk 4
Wk 5
Wk 6
Wk 7
Call Volume
Wk 8
Wk 9
Wk 10
Wk 11
Wk 12
Wk 13
Service Level
Wk 14
Wk 15
7.A.6.a
Packet Pg. 155
Go Live Activity
Autopays
60,000
Data thru 1/10/16
48,573
Bank Draft
50,000
40,617
40,000
30,000
Pre-Go Live:
45,000 CC Autopays
20,000
Credit Cards
10,000
140,000
120,000
Smart Hub Registrations
Pre-Go Live: 110,000 registrations
117,439
100,000
80,000
60,000
40,000
20,000
0
0
Bank Draft
Credit Card
Paperless Billing
Registrations
• Data through January 10, 2016
64,055
70,000
Pre-Go Live Total
60,000
50,000
• Credit Card Autopay totals are over 40,000
• Many members have moved to Bank Draft
Autopays, over 48,000
40,000
30,000
Pre-Go Live: 18,400 accts
20,000
10,000
0
Pre-Go Live Total
Paperless Accts
7.A.6.a
• Smart Hub registrations surpassed previous levels,
new and re-registrations increasing
• Paperless billing far exceeds previous amounts,
Smart Hub prompting members to enroll
Packet Pg. 156
Member Services
Going Forward
• Anticipate response times to stabilize post holiday traffic
fluctuations with member contacts
• Collection activities will begin toward the end of January:
o
o
o
Courtesy Calls – Last week of January
Collection Calls – First week of February
Disconnections – First week of February
• Collection efforts will begin in small increments as staff are
acclimated to new system processes
• Once collections are underway and any potential issues are
resolved, bad debt reduction goals will be communicated that
will positively impact all KPI target metrics
7.A.6.a
Packet Pg. 157
Information Technology Update
January 19, 2016
Lawanda Parnell
Chief Information Officer
Attachment: IT Report January 2016 Board Meeting (3350 : Information Technology
7.A.7.a
Packet Pg. 158
Storage & Server Reallocation
• Reclaimed and/or reallocated from SAP and P8
decommissions
– 70 virtual servers
– 30.5 terabytes of storage*
– 560 gigabytes of RAM
7.A.7.a
* 1 terabyte can store 150 hours of HD recordings
Packet Pg. 159
Handheld Bill Scanner Pilot
• Locations
– Cedar Park
– Marble Falls
– Kyle
• Total transactions (12/10/2015 - 1/6/2016)
– 2955
• Value
– Faster transaction completion with members
– Increased transaction accuracy
– Fewer keystrokes
7.A.7.a
Packet Pg. 160
Smart Safes & Check Scanners
•
•
•
•
•
•
•
Kyle
Johnson City/HQ
Cedar Park
Oak Hill
Blanco
Dripping Springs
Canyon Lake
•
•
•
•
•
•
•
Marble Falls
Liberty Hill
Junction
Bertram
Bulverde
Lake Creek
Lake Travis
7.A.7.a
Packet Pg. 161
Payment Kiosks
• First drive-thru kiosks coming in February
– Cedar Park
– Dripping Springs
• 24x7 availability
• Cash, credit card & E-check
7.A.7.a
Packet Pg. 162
Additional Initiatives Underway
• NISC Phases 1.X and 2.X
– PEC Roundup
– Energy Solutions Loan (On-bill financing)
– AppSuite (additional mobile device function)
– Warehouse bar coding
– Outage map
– Outage management
– Mapping/GIS
7.A.7.a
Packet Pg. 163
Additional Initiatives Underway
• Mobile Device Management: AirWatch
– Monitor, manage & secure mobile devices
• Employee Informational Displays
•
•
•
•
– Communicate PEC & CEO messages to employees
Voice over IP (VOIP) & new telephony devices
Upgrade Auditorium video & audio systems
Exchange and MS Office upgrades
Additional cyber security training and awareness
7.A.7.a
Packet Pg. 164
Questions
7.A.7.a
Packet Pg. 165
7.B.1
Board of Directors
Meeting: 01/19/16 09:00 AM
PO Box 1
DOC ID: 3315
Subject: 2016 NRECA Annual Membership Dues
Background:
Membership in NRECA (National Rural Electric Cooperatives Association) provides the ability
for members to take legislative action, stay informed with technology, industry, and politics, and
collaboration between other cooperatives. Membership also provides opportunities to
participate in international and youth programs.
Below is a historic table of membership dues paid to NRECA which is based on statistical data
for the number of consumers at Pedernales Electric:
2013 - $149,933.00
2014 - $151,165.00
2015 - $158,100.00
Expenditure of Cooperative funds estimated in the amount of $161,427.00 currently included in
the Cooperative's 2016 operating budget; No expenditures of staff time other than ordinary
processing requirements.
ATTACHMENTS:

NRECA Dues-Invoice-2016
(PDF)
Updated: 1/15/2016 11:59 AM by Aisha N Hagen
Packet Pg. 166
Page 1
7.B.1
Regular Meeting
January 19, 2016
NRECA 2016 Annual Membership Dues - J Hewa
RESOLVED BY THE BOARD OF DIRECTORS OF THE COOPERATIVE, that the
Membership dues to the National Rural Electric Cooperative Association for 2016 in the
amount of $161,427.00 are hereby approved, and the Chief Executive Officer of the
Cooperative, or his designee, is hereby authorized and directed to pay those dues pursuant
to the invoice duly presented to the Cooperative.
Updated: 1/15/2016 11:59 AM by Aisha N Hagen
Packet Pg. 167
Page 2
7.B.1.a
Invoice
Date:
1/12/2016
Invoice #:
1510755
Vendor Account #:
931
NRECA MEMBERSHIP DUES
For Member Year Beginning: 2/2/2016
NRECA Distribution Member
2016 Membership Dues (Base Amount)
$86,275.00
Plus Allocation of Additonal Dues - 2014 Statistical Data Used for Calculations
Number of Consumers
Per Consumer
First 10,000 Consumers
X
0.5382
$5,382.00
Next 40,000 Consumers
X
0.2691
$10,764.00
X
0.1794
$37,755.00
Sub Total
$53,901.00
Plus Allocation of CRN Dues
Number of Consumers
Per Consumer
First 10,000 Consumers
X
0.21218
$2,122.00
X
0.10609
$4,244.00
X
0.07073
$14,885.00
Sub Total
Total Consumers:
$21,251.00
260,450
Total Membership Dues Payable
$161,427.00
NRECA has estimated that 13% of the 2016 dues is allocated to lobbying expenses to which IRC Section 162(2)(3) and 6033(e)(1) as
amended apply. Consequently, this portion of your 2016 system dues is not deductible for federal income tax purposes.
Attachment: NRECA Dues-Invoice-2016 (3315 : 2016 NRECA Annual Membership Dues)
Mr. John D. Hewa
Pedernales Electric Co-op, Inc.
PO Box 1
Johnson City, TX 78636-0001
By paying this invoice, the organization represents that its ownership, purpose, structure, operations, and activities have not changed significantly, and that it
remains eligible for the category of NRECA membership to which it is assigned. If you have questions about membership eligibility, please contact Membership at
703 907 5868, or by email at [email protected].
PLEASE RETURN A COPY OF INVOICE WITH
REMITTANCE
Direct payments to: NRECA
PO Box 758777, Baltimore, MD 21275-8777
Payment is due February 11, 2016. Please
make check payable to NRECA.
$161,427.00
Contributions or gifts to NRECA are NOT deductible as charitable contributions for federal invoice tax purposes. However,
payments ARE deductible by members as an ordinary and necessary business expense. NRECA Taxpayer Identification
Number: 53-0116145.
Packet Pg. 168
4301 Wilson Blvd. - Arlington, VA 22203-1860 - tel: 703.907.6875
7.B.3
Board of Directors
Meeting: 01/19/16 09:00 AM
PO Box 1
DOC ID: 3343 C
Subject: Amendments to On-Bill Financing Loan Policy and Underwriting Guidelines and Tariff
Amendment
Background:
The Cooperative previously approved in September 2015 an on-bill financing program for
distributed renewable solar photovoltaic systems to be effective January 1, 2016 and approved
amendments to its Loan Policy and Underwriting Guidelines for the program in December 2015.
The Cooperative is updating the Tariff to address certain fees and updating the Loan Policy and
Underwriting Guidelines for other necessary changes.
Expenditure of Cooperative funds used for the administration of the On-Bill Financing Program
will be recovered through the program fees.
ATTACHMENTS:

2016-1-19 Tariff re On Bill Financing Program version 3 ANH

1-19-16 loan policy re on bill financing version 5 ANH

On-Bill Financing Board Update 1-15-16 V3 (PDF)
(PDF)
(PDF)
Updated: 1/15/2016 12:42 PM by Renee Oelschleger C
Packet Pg. 169
Page 1
7.B.3
Regular Meeting
January 19, 2016
Amendments to On-Bill Financing Loan Policy and Underwriting
Guidelines and Tariff Amendment - B Beavers
COOPERATIVE that the Cooperative approve amendments to its Loan Policy and Underwriting
Guidelines for the on-bill financing program as attached hereto and approve amendments to its
Tariff for the program as attached hereto;
BE IT FURTHER RESOLVED BY THE BOARD OF DIRECTORS OF THE COOPERATIVE
that the Chief Executive Officer, or his designee(s), is hereby authorized and directed to do any
and all such other things, and take such other actions, as the Chief Executive Officer, or his
designee(s), deems necessary or desirable in his reasonable discretion to effectuate this
resolution.
Updated: 1/15/2016 12:42 PM by Renee Oelschleger C
Packet Pg. 170
Page 2
Tariff
For Electric Service Provided by
201 South Avenue F
P.O. Box 1
Johnson City, Texas 78636-0001
Adopted 06-15-2009; Amended 08-16-2010; 9-20- 2010; 12-20-2010; 4-18-11; 9-19-11; 5-21-12; 3-18-13; 4-15-13;
5-20-13; 8-19-13; 1-21-14; 3-17-14; 4-21-14; 9-30-14; 1-20-15; 7-21-15; 9-14-15; 9-21-15; 10-20-15; 1-19-16
Adopted 06-15-2009; Amended 8-16-2010; 9-20-2010; 12-20-2010; 4-18-11; 9-19-11; 5-21-12; 3-18-13; 4-15-13; 5-20-13; 8-19-13; 1-21-14;
3-17-14; 4-21-14; 9-30-14; 1-20-15; 7-21-15; 9-14-15; 9-21-15, 10-20-15; 1-19-16
Packet
Attachment: 2016-1-19 Tariff re On Bill Financing Program version 3 ANH (3343 : Amendments to On-Bill Financing Loan Policy and
7.B.3.a
Pg. 171
PEDERNALES ELECTRIC COOPERATIVE, INC. TARIFF7.B.3.a
100
RATE SCHEDULES ................................................................................................................................................................. 4
GENERAL PROVISIONS ........................................................................................................................................................................... 4
100.1 RESIDENTIAL AND FARM/RANCH (R) ......................................................................................................................................... 5
100.2 WATER WELL (W) ...................................................................................................................................................................... 5
100.3 SMALL POWER (SP) .................................................................................................................................................................... 5
100.4 LARGE POWER (LP) ..................................................................................................................................................................... 6
100.5 INDUSTRIAL POWER (IP)............................................................................................................................................................. 6
100.6 POWER PLANT START POWER (PPSP) ........................................................................................................................................ 7
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) ............................................................................. 9
100.13 POWER COST RECOVERY (PCR)................................................................................................................................................ 9
100.14 WHOLESALE TRANSMISSION POLICY (WTS)........................................................................................................................... 10
100.15 WHOLESALE DISTRIBUTION SERVICE (WDS).......................................................................................................................... 11
100.16 FACILITIES RENTAL RIDER (FRR) ........................................................................................................................................... 13
100.17 FRANCHISE FEE ....................................................................................................................................................................... 14
100.18 REVENUE ADJUSTMENT FACTOR ............................................................................................................................................. 14
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 [DISCONTINUED EFFECTIVE OCTOBER 1, 2015] ................................................................... 16
200.7 CONTINUITY OF SERVICE .......................................................................................................................................................... 16
200.8 SERVICE MONITORING [DISCONTINUED EFFECTIVE SEPTEMBER 1, 2013]................................................................... 16
200.8.5 ADVANCED METERING OPT OUT PROGRAM ........................................................................................................................... 16
200.9 METER TAMPERING .................................................................................................................................................................. 17
200.10 BILLING ................................................................................................................................................................................... 17
200.11 UNDER-BILLING AND OVERBILLING ........................................................................................................................................ 17
200.12 PAYMENT ................................................................................................................................................................................ 18
200.13 PAYMENT OPTIONS ................................................................................................................................................................. 18
200.14 INTERCONNECTION .................................................................................................................................................................. 19
200.15 DISCONNECTION OF SERVICE .................................................................................................................................................. 19
200.16 RECONNECTION FEE ................................................................................................................................................................ 20
200.17 DISPUTED BILLS ...................................................................................................................................................................... 20
200.18 MEMBER COMPLAINTS ............................................................................................................................................................ 20
200.19 RETURNED CHECK/DENIED BANK DRAFT/DENIED CREDIT CARD .......................................................................................... 20
200.20 MEMBER VOTING .................................................................................................................................................................... 20
200.21 MEMBER ACCESS TO COOPERATIVE RECORDS ........................................................................................................................ 20
200.22 ACCOUNT RESEARCH SERVICES .............................................................................................................................................. 21
200.23 EASEMENT RELEASE ............................................................................................................................................................... 21
200.24 SWITCHOVER POLICY ............................................................................................................................................................... 21
200.25 STATUS OF THE POLICY ........................................................................................................................................................... 21
300
300.1
300.2
300.3
300.4
LINE EXTENSION POLICY ................................................................................................................................................ 22
GENERAL POLICY ..................................................................................................................................................................... 22
PERMANENT OVERHEAD RESIDENTIAL, FARM, AND RANCH SERVICE ...................................................................................... 22
OTHER RESIDENTIAL, FARM, AND RANCH OVERHEAD SERVICE EXTENSIONS.......................................................................... 23
OTHER OVERHEAD LINE EXTENSIONS ...................................................................................................................................... 24
TABLE OF CONTENTS
Adopted 06-15-2009; Amended 8-16-2010; 9-20-2010; 12-20-2010; 4-18-11; 9-19-11; 5-21-12; 3-18-13; 4-15-13; 5-20-13; 8-19-13; 1-21-14;
3-17-14; 4-21-14; 9-30-14; 1-20-15; 7-21-15; 9-14-15; 9-21-15, 10-20-15; 1-19-16
Packet Pg. 172
300.5 RESIDENTIAL DEVELOPMENTS ................................................................................................................................................. 25
300.6 COMMERCIAL DEVELOPMENTS................................................................................................................................................. 26
300.7 UNDERGROUND SERVICE.......................................................................................................................................................... 27
300.8 TEMPORARY SERVICE ............................................................................................................................................................... 28
300.9 AREA LIGHTING........................................................................................................................................................................ 28
300.10 LINE CLEARANCE .................................................................................................................................................................... 28
300.11 OWNERSHIP OF DISTRIBUTION FACILITIES .............................................................................................................................. 28
300.12 NO REFUND OF AID TO CONSTRUCTION .................................................................................................................................. 28
300.13 RELOCATION OF FACILITIES .................................................................................................................................................... 29
300.14 FORMULA FOR CALCULATING CONTRIBUTION IN AID OF CONSTRUCTION ............................................................................... 29
300.15 STATUS OF THE POLICY ............................................................................................................................................................ 30
400
CREDIT REQUIREMENTS AND DEPOSITS .................................................................................................................... 31
400.1
400.2
400.3
400.4
400.5
400.6
400.7
400.8
400.9
400.10
500
CREDIT REQUIREMENTS FOR PERMANENT RESIDENTIAL APPLICANTS AND MEMBERS. ........................................................... 31
CREDIT REQUIREMENTS FOR NON-RESIDENTIAL MEMBERS OR APPLICANTS. .......................................................................... 31
DEPOSITS AND GUARANTEE AGREEMENTS. ........................................................................................................................... 31
DEPOSITS FOR TEMPORARY OR SEASONAL SERVICE AND FOR WEEKEND RESIDENCES. ........................................................... 33
AMOUNT OF DEPOSIT. ............................................................................................................................................................ 33
INTEREST ON DEPOSITS. ......................................................................................................................................................... 33
RECORDS OF DEPOSITS........................................................................................................................................................... 33
REFUNDING DEPOSITS AND VOIDING LETTERS OF GUARANTEE. ............................................................................................. 34
RE-ESTABLISHMENT OF CREDIT. ............................................................................................................................................ 34
STATUS OF CREDIT AND DEPOSIT REQUIREMENTS. .......................................................................................................... 34
FEE SCHEDULE ................................................................................................................................................................... 35
Adopted 06-15-2009; Amended 8-16-2010; 9-20-2010; 12-20-2010; 4-18-11; 9-19-11; 5-21-12; 3-18-13; 4-15-13; 5-20-13; 8-19-13; 1-21-14;
3-17-14; 4-21-14; 9-30-14; 1-20-15; 7-21-15; 9-14-15; 9-21-15, 10-20-15; 1-19-16
Packet Pg. 173
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 –
a. For residential service, 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.
b. For all other services, the Point of Delivery is that point, as determined by the Cooperative, where the
electric power and energy leaves the Cooperative electric delivery system, regardless of the metering
location provided that the voltage service level at the metering location is the same as that at the delivery
point.
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
*7200 V
*14400 V
120/208 V (wye)
*120/240 V (delta)
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.
Page 4
Adopted 06-15-2009; Amended 8-16-2010; 9-20-2010; 12-20-2010; 4-18-11; 9-19-11; 5-21-12; 3-18-13; 4-15-13; 5-20-13; 8-19-13; 1-21-14;
3-17-14; 4-21-14; 9-30-14; 1-20-15; 7-21-15; 9-14-15; 9-21-15, 10-20-15; 1-19-16
Packet
Pg. 174
Applicability - Applicable to individually metered residences, farms, ranches, and their facilities.
Rates
Service Availability Charge:
$22.50 per month
Delivery Charge [This rate shall become effective December 1, 2014]:
$0.02712 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
$19.50 per month
$0.02712 per KWH
100.3 Small Power (SP)
Applicability - Applicable to all commercial and industrial members whose rolling 12-month average 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
$37.50 per month
$0.02101 per KWH
100.1 Residential and Farm/Ranch (R)
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Applicability - Applicable to all commercial and industrial members whose rolling 12-month average demand is 75
kilowatts but less than 10,000 kilowatts, and whose use is not covered by another specific rate schedule.
Rates
$150.00 per month
Capacity Delivery Charge [This rate shall become effective December 1, 2014]:
Secondary Level Service
$3.38 per kW
Primary Level Service
$3.31 per kW
The member's Capacity Delivery Charge will be calculated using the kW load established by member
during the 15-minute period of maximum use during the month but will not be less than 75kW.
Delivery Charge [These rates shall become effective December 1, 2014]:
Secondary Level Service
$0.00885 per KWH
Primary Level Service
$0.00867 per KWH
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
$1,000.00
Capacity Delivery Charge [This rate shall become effective December 1, 2014]:
$.84000 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.
100.4 Large Power (LP)
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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
$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.
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)
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
Delivery Charge:
As per the otherwise applicable tariff.
As per the otherwise applicable tariff.
Recovery (PCR) Tariff for Renewable
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.
100.6 Power Plant Start Power (PPSP)
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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 own, furnish, install, and maintain lights on its existing facilities. If
additional facilities are requested or 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. Beginning May 1, 2014, only LED lamps will be available.
Upon failure of any currently owned Cooperative owned lighting, such lighting will be replaced with LED lighting and
applicable charges will apply.
Any member requesting a change from an existing, working lamp to LED lighting will pay $250 for the first light and
$180 for each additional light change out requested by the same member at the same basic location and at the same
time.
This rate applies only to Cooperative owned lighting. Member owned street lighting is billed under 100.3 Small Power
Rate.
Rates
Delivery Charges:
Lamp Size
50-55 watt
(comparable to
100 watt HPS
100-110 watt
(comparable to
250 watt HPS)
kWh per month
Charge
per Lamp
LED
19
kWh per month
$9.60
LED
38
kWh per month
$20.00
100 watt
HPS*
45
kWh per month
$ 8.15
250 watt
HPS*
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
* These lamps will no longer be available for new installations effective May 1, 2014.
Base Power Cost: The per kWh base power cost for Power Supply Charges stated in the Power Cost
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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:
Basic PCA =
A-B+C
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
=
A
=
B
=
Power Cost Recovery (expressed in $ per kWh) to be applied to estimated
energy sales for the billing period.
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.
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
C
=
=
(D)(kWhs) minus $0.005 per kWh of the kWh sold to Renewable Power
Members.
Base power cost of $0.07208 per kWh sold
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.
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.
100.12 Interruptible Service Rider (ISR) (discontinued after 06-15-2009)
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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.
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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
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-toconstruction 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
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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.
The Cooperative will provide distribution service to any eligible member, provided that:
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In the event that existing facilities are adequate to support the requested distribution service, service will be priced in
accordance with Pricing above.
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-toconstruction 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.
100.16 Facilities Rental Rider (FRR)
Applicability - This service is available under the Cooperative’s Facilities Rental Service Agreement, which
Agreement shall include a minimum seven (7) year term. This service applies to Cooperative-owned distribution
facilities that are in excess of the standard facilities and services that the Cooperative would normally provide under
the applicable tariff schedule(s).
Rental Charges - The monthly rental charge for facilities owned, operated, and maintained by the Cooperative
("Monthly Facilities Rental Charge"), will be derived by multiplying the total calculated installed cost of the facilities to
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be rented (determined at the time of the signing of the Facilities Rental Service Agreement) times 1.3% ("Monthly
Facilities Rental Rate"). The Member is responsible for the Monthly Facilities Rental Charge beginning with the
effective date of initiating service or the date installation of the facilities was completed if the facilities were installed
after the execution of the Facilities Rental Agreement, whichever occurs later.
Monthly Facilities Rental Charge = calculated installed cost x 0.013 (Monthly Facilities Rental Rate)
Terms of Payment - Member shall pay the Monthly Facilities Rental Charge on a monthly basis, and the Monthly
Facilities Rental Charge will be due and payable with the Member’s monthly bill for electric service.
Terms and Conditions - Should Cooperative-owned facilities require replacement during the term of the Facilities
Rental Service Agreement, the total calculated installed cost of the facilities will be recomputed and increased or
decreased, as the case may be by: (1) The total installed cost of the replacement equipment, including the costs of
acquiring the replacement equipment, less (2) The installed cost of the original equipment.
Should the Member request that any of the rented facilities installed, owned, maintained or operated by the
Cooperative be removed, or upon termination of service at a location without a new Member willing to continue a
contract to rent the facilities. The Cooperative will remove such facilities within a reasonable amount of time at the
Member’s expense.
100.17 Franchise Fee
Municipal franchise fee charges are applicable to all members served by the Cooperative inside a municipal corporate
boundary, and are in addition to any other charges made under the Cooperative's tariff for electric service. All current
and future franchise fees not included in base rates shall be separately assessed for member service provided within
the municipality where the franchise fee is authorized. The portion of the franchise fee not included in base rates will
appear on the bill as a separate line item. The franchise fee is calculated by multiplying the franchise fee percentage
assessed by the municipality by the charges for energy and power sold and such other authorized charges to a
member excluding any taxes and other authorized exclusions.
100.18 Revenue Adjustment Factor
Applicability - This tariff is applicable to all rates except Industrial and Power Plant Start Power.
For all kilowatt-hours sold to members taking service under all rates except Industrial and Power Plant Start
Power, the Revenue Adjustment Factor (RAF) will be calculated as follows:
RAF = -1 x (R / S) expressed in $ / kWh
Where:
R = Estimated revenues in excess of those needed for the time period
S = Forecasted or average kilowatt-hour sales for the time period being adjusted
The RAF is then multiplied by the kWhs billed to each member in a billing cycle and applied to a member's bill for
the particular time period subject to adjustment. Application of the RAF is intended to decrease a member's bill.
Use of the RAF and the timeframe for application of the RAF to a member’s bill, including the starting and end
dates for RAF, must be approved by the Board of Directors by adoption of a Board Resolution.
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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. For good cause, including for natural disasters or other declared
emergencies, the Chief Executive Officer may waive, suspend, or modify the Establishment Fee for a limited duration to
address the circumstances. After a good cause determination, the Chief Executive Officer must inform the Board of
Directors at its next Regular Meeting of all actions taken under this section.
200.4 Same Day Service Fee
If service is available at a location and a request for same day connection is made 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, deposits, if any, and other fees required.
Service reconnections after non-payment will not be performed after normal business hours unless the Cooperative
determines otherwise. In the event any service reconnections after non-payment are performed after normal business
200
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hours on Monday through Friday or on Saturdays or Sundays, a non-refundable same-day service fee of $250 will be
required to be paid prior to reconnection. This fee is in addition to the past due balance, reconnection fee, deposits and
any other fees required. For good cause, including for natural disasters or other declared emergencies, the Chief
Executive Officer may waive, suspend, or modify the Same Day Service Fee for a limited duration to address the
circumstances. After a good cause determination, the Chief Executive Officer must inform the Board of Directors at its
next Regular Meeting of all actions taken under this section.
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 [DISCONTINUED EFFECTIVE OCTOBER 1, 2015]
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 [DISCONTINUED EFFECTIVE SEPTEMBER 1, 2013]
200.8.5 Advanced Metering Opt Out Program
The Advanced Metering Opt Out Program only applies to residential accounts (other than residential accounts with
interconnection agreements). A member may request to opt out from use of the Cooperative's advanced meter at a
service location. The Cooperative may grant such request subject to certain qualifications and conditions.
A. Meter Exchange Fee
A $75 meter exchange fee will be charged for any meter exchange at any service location already equipped with an
advanced meter. Any member participating in the Advanced Metering Opt Out Program for new service locations will be
required to pay the Cooperative’s establishment fee as outlined in the Cooperative’s Tariff for each location.
B. Automatic Payments
To participate in the Advanced Metering Opt Out Program, a member must authorize automatic payments through
either the Credit Card Payment Plan or Bank Draft Payment Plan. If a member cancels authorization for automatic
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payments, then the meter will be exchanged for an advanced meter and the member will be unable to participate in the
Advanced Metering Opt Out Program.
C. Meter Readings
Each member participating in the Advanced Metering Opt Out Program will be charged a fee of $30.00 each month for
non-standard manual meter readings by the Cooperative and for processing of such readings for each service location.
An additional $1 per mile charge for service locations further than 20 miles from nearest area office will apply.
If for any month a meter is unable to be read by the Cooperative, the monthly fees will apply and the usage for that month
will be estimated based on the member’s previous usage. Any under-billing or overbilling resulting from such estimate will
be adjusted after the meter is read.
If a member has paid bills for service for 12 consecutive residential billings (i) without having service disconnected for
nonpayment of a bill, (ii) without having been delinquent in the payment of bills more than once, and (iii) has not had more
than one returned check, a member participating in the Advanced Metering Opt Out Program may then request a
quarterly read schedule. In this event, the member participating in the Advanced Metering Opt Out Program will be
charged a fee of $45.00 each quarter for non-standard manual meter readings by the Cooperative and for processing of
such readings for each service location. An additional $1 per mile charge for service locations further than 20 miles from
nearest area office will apply.
For any member on a quarterly read schedule, the monthly fees will still apply and the usage for each month will be
estimated based on the member’s previous usage. Any under-billing or overbilling resulting from such estimate will be
adjusted after the meter is read quarterly.
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. Any governmental entity
asserting eligibility to be billed under Texas Government Code Chapter 2251 may file a written notice asserting their
eligibility, and the Cooperative will determine whether the entity is subject to that statute. Bills to all non-residential
accounts other than state agencies or other governmental entities that the Cooperative has approved as being subject to
Texas Government Code Chapter 2251, 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 or other governmental
entities that the Cooperative has approved as being subject to Texas Government Code Chapter 2251, shall be in
accordance with that statute. 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.
200.11 Under-billing and Overbilling
If charges are found to be higher than authorized in the Cooperative’s tariffs or if the Cooperative fails to bill a member for
services, then a billing adjustment will be calculated by the Cooperative and applied in the manner described herein.
Notwithstanding the foregoing, any billing adjustments greater than $5,000 may be adjusted to the date of error if
identified by the Cooperative.
A. Under-billing
1. If the member’s account is under-billed because of failure to receive meter readings, faulty metering equipment or
other equipment error resulting in unreported use, the Cooperative will estimate the unbilled amount and adjust
the member’s bill accordingly, up to 3 months.
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2. If the member’s account is under-billed because of billing, rate assignment, processing errors or other similar
circumstance resulting in unreported use, the Cooperative will estimate the unbilled amount and adjust the
member’s bill accordingly, up to 6 months.
3. If the member’s account is under-billed because of meter tampering, bypass, diversion or other similar
circumstance resulting in unreported use, the Cooperative will estimate the unbilled amount and adjust the
member’s bill accordingly for the entire period of unreported use.
A deferred payment arrangement may be available for any periods of under-billing except for such periods resulting from
meter tampering, bypass, diversion or other similar circumstance.
B. Overbilling
1. If the member’s account is overbilled because of billing, rate assignment, processing errors or other similar
circumstance, the Cooperative will adjust the member’s bill accordingly for the entire period of overbilling.
2. If the member’s account is overbilled because of failure to receive meter readings, faulty metering equipment or
other equipment error, the Cooperative will adjust the member’s bill accordingly for the entire period of overbilling.
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 and when applicable a same day service fee. 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 total
billings divided by 366 days. A true-up and recalculation will be required no more than every 12 months. Upon
such true-up and recalculation, any overpayments or underpayments shall either be credited or debited from the
account as applicable. The amount of any underpayment will be added to the amounts due. The amount of any
overpayment will be deducted from any amounts owed. 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. 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. (
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 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. 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.
 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.
200.14.5 On-Bill Financing Program [EFFECTIVE JANUARY 1 FEBRUARY 15, 2016]
Any consumer loan to a member with the Cooperative must be in accordance with the Cooperative’s On-Bill Financing
Program Manual, any underwriting guidelines, and only after execution of the Cooperative’s required loan and security
agreements.
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.
Failure to pay guaranteed amount 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.
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The Cooperative will assess a $100.00 fee for reconnection after non-payment. Service reconnections after non-payment
will not be performed after normal business hours unless the Cooperative determines otherwise. In the event any service
reconnections after non-payment are performed after normal business hours on Monday through Friday or on Saturdays
or Sundays, a non-refundable same-day service fee of $250 will be required to be paid prior to reconnection. This fee is in
addition to the past due balance, reconnection fee, deposits and any other fees required. For good cause, including for
natural disasters or other declared emergencies, the Chief Executive Officer may waive, suspend, or modify the
Reconnection Fee for a limited duration to address the circumstances. After a good cause determination, the Chief
Executive Officer must inform the Board of Directors at its next Regular Meeting of all actions taken under this section.
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.
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 Chief Executive Officer or designee of the Chief Executive Officer. 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
200.16 Reconnection Fee
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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 may be charged to the requestor.
200.23 Easement Release
The Cooperative will assess a $300.00 fee for processing an Application for Easement Release.
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 at any time by the Board of Directors.
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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:
B.
(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.
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.
(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
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applicant shall be required to pay as aid to construction the estimated cost of the extension in
excess of such amount.
D.
E.
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.
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 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:
B.
(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.
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)
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)
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
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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.
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:
B.
(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.
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)
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:
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
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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.
(3)
D.
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.
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.
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.
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;
(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;
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B.
(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.
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 and secondary conductors and
any electric equipment, and devices required for service to the development. The estimate for
these facilities will be 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. The estimate will not include costs for voltage transformation or services.
(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.
(3)
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.
(4)
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.
(5)
All amounts paid to the Cooperative for construction shall be non-refundable.
(6)
All Cooperative facilities required within the limits of the subdivision will be installed on a schedule
set by the Cooperative based on the necessary load requirements but 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:
(4)
(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.
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 above conditions. In addition, when
receiving underground service, the member will be responsible for providing all trench and associated
backfill, concrete work associated with padmounted gear, and all conduit and its installation.
C. Underground Service to Subdivisions or Commercial Developments:
Where a developer requests the construction of underground electric facilities within a platted subdivision
or commercial development, 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. The developer shall be responsible for providing all trench and associated backfill,
concrete work associated with padmounted gear, and all conduit and its installation.
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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.
F. For Commercial/Industrial/multi-family residential underground services where the meter or a bank of
meters is to be located on the building or adjacent to the load, the service (cable, conduit, and trench)
from the transformer to the load will be provided by the Member/developer.
In those cases where the number of service cables will exceed the number of termination points on
secondary terminal of the transformer, a tap box (per PEC Specifications) is to be provided by
Member/developer. The Member/developer will provide the entire service, from the transformer to
tap box to the load. The number of cables from the transformer to the tap box shall not exceed
number of termination points on the secondary terminal of the transformer.
the
the
the
the
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 except
those services installed past the point of delivery as defined in Section 100 General Provisions, 4. Point of
Delivery. 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.
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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
(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.
300.13 Relocation of Facilities
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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.
300.15 Status of the Policy
The Line Extension Policy is subject to change by the Board of Directors.
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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.
(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)
400.2
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.
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 onesixth 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 and Guarantee Agreements.
(A)
(1) An applicant, who has not previously received service from the Cooperative, will be required to pay:
(a)
a fixed deposit in the amount of $150 for residential service or $300 for non-residential service 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
(b)
a fixed deposit in the amount of either $75 or $150 for residential service or $300 for nonresidential service 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
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assessment conducted by the Cooperative or on its behalf. The amount of the deposit due will be
based on a credit risk assessment.
(2) An existing member when applying for additional electric service, will be required to pay:
(a)
a fixed deposit in the amount of $150 for residential service or $300 for non-residential service in
the event the existing member fails to provide complete, accurate and verifiable identification
information when requested by the Cooperative; or
(b)
a fixed deposit in the amount of either $75 or $150 for residential service or $300 for nonresidential service 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. The amount of the deposit due
will be based on a credit risk assessment.
(3) 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.
(4) 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 either $75 or $150 for residential service (the amount of the deposit due will be based on a
credit risk assessment) 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.
(B)
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.
(C)
Notwithstanding the foregoing, if the applicant or existing member has been determined to be a victim of
family violence as defined in the Texas Family Code §71.004, such person will not be required to pay either
an initial or additional deposit when establishing new service. This determination shall be evidenced by
submission to the Cooperative of a certification letter developed by the Texas Council on Family Violence
within 10 business days of the application for service. This waiver in Section 400.3(C) shall only be applied
towards an initial or additional deposit for a single location for the applicant or existing member unless
another certification letter is later provided. Any reconnections after nonpayment will be subject to payment
of the past due balance, reconnection fee, deposits and any other fees required.
(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.
(E)
Guarantees of residential member accounts.
(1) A guarantee agreement between the Cooperative and a guarantor with satisfactory credit must be in
writing and shall be for no more than the amount of the initial deposit the Cooperative would require on
the applicant's account pursuant to subsection (A) of this section. The amount of the guarantee shall be
clearly indicated in the signed agreement. A guarantor can establish satisfactory credit by 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 guarantor is not late in paying a bill more than once, (ii) the
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guarantor does not have service disconnected for nonpayment; and (iii) the guarantor does not have
more than one returned check.
(2) The guarantee shall be voided and returned to the guarantor according to the provisions of Section
400.08.
(3) Upon default by a residential member the guarantor of that member's account shall be responsible for
the unpaid balance of the account only up to the amount agreed to in the written agreement.
(4) The Cooperative shall provide written notification to the guarantor of the member's default, the amount
owed by the guarantor, and the due date for the amount owed.
(5) The Cooperative shall provide the guarantor a bill which will include the payment due date which will
not be less than 16 days after issuance.
(6) The Cooperative may transfer the amount owed on the defaulted account to the guarantor's own
service bill provided the guaranteed amount owed is identified separately on the guarantor's bill.
(7) The Cooperative may disconnect service to the guarantor for nonpayment of the guaranteed amount
only if the disconnection was included in the terms of the written agreement, and only after proper
notice as described by subsection (E) of this subsection.
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 payment of interest shall be made
retroactive to the date of deposit. (Effective Sept. 1, 2012)
(A)
(B)
400.7
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.
The deposit shall cease to draw interest on the date it is returned or credited to the member's account.
Records of deposits.
(A)
(B)
(C)
(D)
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.
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.
The Cooperative shall maintain a record of each unclaimed deposit for at least four years.
The Cooperative shall make a reasonable effort to return unclaimed deposits.
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Adopted 06-15-2009; Amended 8-16-2010; 9-20-2010; 12-20-2010; 4-18-11; 9-19-11; 5-21-12; 3-18-13; 4-15-13; 5-20-13; 8-19-13; 1-21-14;
3-17-14; 4-21-14; 9-30-14; 1-20-15; 7-21-15; 9-14-15; 9-21-15, 10-20-15; 1-19-16
Packet
Pg. 203
400.9
Refunding deposits and voiding letters of guarantee.
(A)
If service is not connected, or is disconnected, the Cooperative shall promptly (1) 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 and (2) void and return to the guarantor all letters of guarantee on the account or provide written
documentation that the contract has been voided.
(B)
When the member has paid bills for service for 12 consecutive residential billings or for 24 consecutive nonresidential billings (i) without having service disconnected for nonpayment of a bill, (ii) without having been
delinquent in the payment of bills more than once, and (iii) 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 or void and return the guarantee or provide
written documentation that the contract has been voided. 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. The letter of guarantee may be retained if the
member does not meet the foregoing refund criteria.
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.
400.10 Status of Credit and Deposit Requirements.
The Cooperative's credit and deposit requirements are subject to change at any time by the Board of Directors.
For good cause, including for natural disasters or other declared emergencies, the Chief Executive Officer may
waive, suspend, or modify any credit and deposit requirements for a limited duration to address the
circumstances. After a good cause determination, the Chief Executive Officer must inform the Board of Directors
at its next Regular Meeting of all actions taken under this section.
400.8
Page 34
Adopted 06-15-2009; Amended 8-16-2010; 9-20-2010; 12-20-2010; 4-18-11; 9-19-11; 5-21-12; 3-18-13; 4-15-13; 5-20-13; 8-19-13; 1-21-14;
3-17-14; 4-21-14; 9-30-14; 1-20-15; 7-21-15; 9-14-15; 9-21-15, 10-20-15; 1-19-16
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Pg. 204
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
Refer to Section 300
Line Extension Policy
Refer to Section 100.17 Franchise
Fee
Facilities charge
Franchise Fee
Same day service at existing location
$ 250.00
Real Estate Show Fee [DISCONTINUED AS OF OCTOBER 1, 2015]
Advanced Metering Opt Out Program – Meter Exchange
Advanced Metering Opt Out Program – Monthly Meter Readings
Advanced Metering Opt Out Program – Quarterly Meter Readings
$
75.00
$ 30.00, additional $1/mile charge
for service locations further than 20
miles from nearest area office
$ 45.00, additional $1/mile charge
for service locations further than 20
miles from nearest area office
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
$
Reconnection Fee (reconnection after non-payment)
$ 100.00
Return Check/Denied Bank Draft/Denied Credit Card
$
75.00
30.00
The following fees are effective January 1, 2016 February 15, 2016:
$25.00
Credit Check Report Fee
$70 45.00 (may be refunded if
member signs up for
automatic
payment in connection with the
loan)
Loan Application Fee
500
Page 35
Adopted 06-15-2009; Amended 8-16-2010; 9-20-2010; 12-20-2010; 4-18-11; 9-19-11; 5-21-12; 3-18-13; 4-15-13; 5-20-13; 8-19-13; 1-21-14;
3-17-14; 4-21-14; 9-30-14; 1-20-15; 7-21-15; 9-14-15; 9-21-15, 10-20-15; 1-19-16
Packet
Pg. 205
Document Preparation Fee
$45.00
$5515.00
Filing Fees
Tax Monitoring Fee
$20.00
Loan Administration Fee
One Percent (1.0%) shall be added
as interest collected on the loan
Loan Late Fee
May be assessed after 10 days of
payment due date; greater of five
Percent (5%) on amount due or
$7.50
Open Records Fee – Staff research time
$
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.
40.00 per hour
Actual cost
Account Research Services by Subpoena
$
40.00 per hour
Easement Release
$ 300.00
Page 36
Adopted 06-15-2009; Amended 8-16-2010; 9-20-2010; 12-20-2010; 4-18-11; 9-19-11; 5-21-12; 3-18-13; 4-15-13; 5-20-13; 8-19-13; 1-21-14;
3-17-14; 4-21-14; 9-30-14; 1-20-15; 7-21-15; 9-14-15; 9-21-15, 10-20-15; 1-19-16
Packet
Pg. 206
7.B.3.b
LOAN POLICY AND UNDERWRITING GUIDELINES
Approved: September 14, 2015
Revised: December 17, 2015, January 19, 2016
PEC attempts to comply with federal and state laws regarding extensions of credit to its members.
Members eligible for this financing program must meet creditworthiness standards including evaluation
of payment history and other criteria as described herein.
In addition, Members will be subject to loan application and credit score checks.
Terms of Loan:





No more than $20,000 for Grid Tied Distributed Energy Resource (DER) Systems, including
distributed renewable solar photovoltaic systems and grid tied battery storage systems installed
by a qualified participating vendor
Repayment of Loan – Ten years or less
Interest – No more than 10%
Residential and Commercial members are eligible
Contingent upon satisfactory installation of grid tied equipment by qualified participating
vendor
Underwriting Guidelines:

For residential service, during the most recent 12 consecutive months of electric service
(i)
(ii)
(iii)

For commercial service, during the most recent 24 consecutive months of electric service
(ii)
(ii)
(iii)



Member must own property in fee simple in which installation to occur.
No tax liens may be filed against the property or otherwise filed against the member.
Loans shall be secured with a security agreement and UCC by a fixture filing on the qualified
equipment . Member shall provide appropriate evidence of insurance. . Eligible commercial
members may be required to provide additional security for the loan.
Attachment: 1-19-16 loan policy re on bill financing version 5 ANH (3343 : Amendments to On-Bill Financing Loan Policy and Underwriting
1-15-16 version 5
Packet Pg. 207














Eligible residential members including joint members must meet the following criteria:
Credit Score
Billing History with no more
then one late payment (Months)
600 - 649
650 - 699
≥ 700
24
18
12
Member annual income or revenues must be three times the loan amount
The DER must meet all PEC interconnection standards.
Financing of all grid tied DER systems is contingent on final approval of installation and
approved interconnection with PEC. .
All joint members must authorize appropriate loan documentation.
Only one loan per account until expiration of any existing loan with PEC
Credit check report fee will be collected upon submission of application. upon request for preapproval
Application fee will be collected upon submission of the member's loan package application and
may be refunded if member signs up for automatic payment in connection with the loan.
Application fee will be collected upon billing history review and credit check review; application
fee will be retained regardless of the decision on the application..
A Tax Monitoring Fee will be collected after review of tax history.
If Member authorizes automatic payments through either the Credit Card Payment Plan or Bank
Draft Payment Plan, then the application fee may be refunded.
A filing fee and a document preparation fee will be collected upon execution of the loan
dcoumentation and completion of the filingsclosing of the loan.
The interest rate of the loan shall be the cost of funds plus an additional one (1) percent for An
administration costs. fee shall be collected as an adder to the interest rate of the loan.
A late fee may be assessed after 10 days of payment due date; greater of five percent (5%) on
amount due or $7.50
Repayment Guidelines:

After approval of installation by PEC and closing the loan, Member's bill will then include a lineitem for repayment of the loan through monthly installments. Monthly payments by Member go
first to the cost of interest and principal of the loan then to the electric service bills.
Collection Standards
7.B.3.b
2
Packet Pg. 208

In case of any delinquencies, any payment by Member goes first to the costs of interest and
principal of the loan then to the electric service bills.
Fair Lending


Credit decisions shall be made without adverse discrimination on the basis of race, color, religion,
sex, national origin, marital status, age (provided the applicant is of legal age and has the capacity
to enter into a binding legal contract), receipt of public assistance, or good faith exercise of rights
under the Consumer Credit Protection Act or any other prohibited basis. PEC will not discourage
the completion or submission of an application for credit by any applicant on any of the
prohibited bases.
It is the intent of the PEC to comply with the requirements of the Equal Credit Opportunity Act
and the Fair Credit Reporting Act as they may apply to any credit program.
7.B.3.b
3
Packet Pg. 209
PEC Energy Solutions Loan
Program Guideline Revisions
January 19, 2015
Attachment: On-Bill Financing Board Update 1-15-16 V3 (3343 : Amendments to On-Bill
7.B.3.c
1 210
Packet Pg.
• Background
• Implementation of an On-Bill Financing Program to support the
Cooperatives’ residential members in obtaining member-owned
distributed generation and grid-tied battery storage.
• Board Consideration
• Approval for amendments to Energy Solutions Loan Program
loan policy and underwriting guidelines and tariff amendments.
• Amendments include:
1. PEC to Review Tax history
2. Secure Loans with UCC and Security Agreement
•
Commercial Service loan may require additional
Security.
3. Change in Fee Structure
Purpose of Today’s Topic
7.B.3.c
Packet Pg. 211
Changes to Fees
Original Fees
Fees
Application
$70.00
Credit check
$25.00
Filing Fee
$55.00
Fee total
$150.00
Proposed Fees
Fees
Credit Check
$25.00
Tax Review
$20.00
Document Preparation
$45.00
Filing Fee
$15.00
Application Fee
$45.00
Fee Total
$150.00
7.B.3.c
Packet Pg. 212
7.B.4
Board of Directors
Meeting: 01/19/16 09:00 AM
PO Box 1
DOC ID: 3349 A
Subject: Construction and Engineering Master Service Agreements_Additional Contractors
Background:
The Cooperative has previously approved various construction and engineering master service
agreements for capital improvement plan electric system improvement projects. The
Cooperative is including two additional contractors.
Expenditure of Cooperative funds as previously included in the Cooperative's Capital
Improvement and Operating budgets; the additional approved contractors may lower
construction costs by providing additional altermatives for projects. No staff time is anticipated
other than ordinary processing requirements.
ATTACHMENTS:

2016_19_Jan_Construction Master Service Agreements_Additional Contractors Memo
Updated: 1/15/2016 10:36 AM by Aisha N Hagen A
(PDF)
Packet Pg. 213
Page 1
7.B.4
Regular Meeting
January 19, 2016
Construction and Engineering Master Service Agreements_Additional
Contractors- B Hicks
COOPERATIVE, that two new distribution construction contractors, Hargrave Power Inc. and
Linetec Services, LLC be added to the list of approved construction contractors; and
Updated: 1/15/2016 10:36 AM by Aisha N Hagen A
Packet Pg. 214
Page 2
Packet Pg. 215
7.B.4.a
Attachment: 2016_19_Jan_Construction Master Service Agreements_Additional Contractors Memo (3349
8.A.1
Board Planning Calendar of Potential Agenda Items
Item
January
March
April
May
January Regular Board Meeting
Receive CEO’s Year in Review Report
Presentation by CEO of Legislative Report
Prior to each Legislative Session (biennial)
Approve TEC Annual Membership Dues
Key Performance Indicator (KPI) Results and Recommendations for KPIJanuary Regular Board Meeting
P2
Present Elections Communications Plan to Board
February
Due Date Notes
Annual Submission of Conflicts of Interest Certification and Disclosure
Forms from Managers
Direct the General Counsel to Prepare Proposed Non-Director Election
Items
Approve NRECA Annual Membership Dues
Appoint representatives for NRECA Legislative Conference
Appoint CRC voting delegates for NRUCFC Forum
Health and Dental Insurance Renewal
Presentation and Approval of Candidate Slate, Ballot, and Any NonDirector Election Items
Report on Property and Liability Insurance Policies
Present Audited Financial Statements
Approve Annual Member Meeting Agenda
At or before January Regular Board Meeting
No later than February Regular Board Meeting
February Regular Board Meeting
March Regular Meeting
April Regular Board Meeting
May Regular Board Meeting
Perform Annual General Counsel Review
During May
Annual Review of Strategic Plan
Approve Form 990
Recognize Veterans with moment of silence
Strategic Item or
Compliance Item
Compliance - Election Policy and
Procedures
Strategic
Compliance - Legislative Policy
Compliance - TEC
Compliance - Strategic Plan
Procedures
Compliance - Conflict of Interest
Policy
Procedures
Compliance - NRECA
Compliance - Legislative Policy
Compliance NRUCFC
Strategic
Procedures
Compliance
Compliance
Compliance - Bylaws
Compliance - General Counsel
Performance Evaluation Policy
Strategic - Annual Review
Compliance
Reoccuring
or Ad-hoc
Reoccurring
Reoccurring
Reoccurring
Reoccurring
Reoccurring
Reoccurring
Reoccurring
Reoccurring
Reoccurring
Reoccurring
Reoccurring
Reoccurring
Reoccurring
Reoccurring
Reoccurring
Reoccurring
Reoccurring
Reoccurring
Reoccurring
Reoccurring
Attachment: Board Calendar of Agenda Items 2016-01-19 (3342 : Board Meeting Planning Calendar (written report in materials))
Board
Meeting
Month
Board Calendar of Agenda Items 2016-01-19 Page 1 of 3 Revised 1/14/2016
Packet Pg. 216
8.A.1
June
Item
Approve Patronage Capital Allocation
June Regular Board Meeting
Updates on Voter Turnout
June Regular Board Meeting
Conduct Annual Meeting
During June
Announcement and Certification of Election Results
June Annual Meeting
Receipt of Director Affirmations, Directors' Code of Conduct and Conflict
At conclusion of Annual Meeting
of Interest forms from newly elected Directors
For Annual Meeting minutes and for first Regular
Receipt of Written Certification of the Election Results
or Special Board Meeting minutes after Annual
Meeting
Strategic Item or
Compliance Item
Compliance - Capital Credits
Policy
Procedures
Compliance - Bylaws
Procedures
Compliance - Code of Conduct,
Conflict of Interest Policies
Reoccuring
or Ad-hoc
Reoccurring
Reocurring
Reoccurring
Reoccurring
Reoccurring
Reoccurring
Procedures
Election of Officers
At first Regular or Special Meeting following
Annual Meeting
Compliance - Bylaws
Reoccurring
Review LCRA Business Plan
June or July Meeting
Strategic
Reoccuring
Orientation of New Directors, including Open Meetings Policy Training
Review and Reaffirm/Amend Committee Charters
Appointment/Reaffirmation of Committee Chairpersons
July
Due Date Notes
Annual Review of Directors’ Code of Conduct by General Counsel
No later than 180th day after the date the Director
Compliance - Open Meetings
assumes responsibilites as a member of the
Board. The General Counsel will ensure this
Policy
training is made available.
Compliance - Board Committee
July Regular Board Meeting
Guidelines
Compliance - Board Committee
Guidelines
Compliance - Code of Conduct
Reoccurring
Reoccurring
Reoccurring
Reoccurring
Annual Review and Submission of Conflicts of Interest Certification and
Disclosure Forms from Directors
Compliance - Conflict of Interest
Reoccurring
Policy
Biennial Board Assessment Review
Compliance - Code of Conduct
Reoccurring-biennial
Compliance - NRECA
Compliance - CFC
Compliance - TEC
Strategic
Reoccurring
Reoccurring
Reoccurring
Reoccurring
Compliance - Strategic Plan
Reoccurring
July Regular Board Meeting (biennial)
Appoint NRECA Voting Delegates for NRECA Regional Meeting
Appoint CFC Voting Delegates for CFC District Meeting
Appoint TEC Delegates for TEC Annual Meeting
4CP Performance Summary
Key Performance Indicator (KPI) Results and Recommendations for KPIJuly Regular Board Meeting
P1
Board
Meeting
Month
Packet Pg. 217
8.A.1
August
September
October
November
December
Item
Due Date Notes
Establish Annual Meeting Date, Time and Location
At or before August Regular Board Meeting
Consider Election Services Contract
At or before August Regular Board Meeting
Post Election Analysis and Annual Review of Election Policy and
Procedures
August Regular Board Meeting
Review of Policy on Policies
Operation Round Up
Integrated Resource Plan - Assumptions, Trends and Findings
Integrated Resource Plan - Results and Recommendations
Key Ratio Trend Analysis (KRTA) Presentation
Integrated Resource Plan - Final Report
Cost of Service Study (COSS) and Rate Design Draft
Recommendations
Emergency Operations Plan Review
Director District Revision
Annual Review of Capital Credits Policy
October Regular Board Meeting
Approve Capital Credits Retirement
Rate Design Changes
Capital Budget Amendment – Facility Extension Fees
Retirement Plan Update from the Plan Administration Committee
Presentation and Approval of Operating Budget, Capital Improvement
Plan (CIP), and Work Plan
Recognize Veterans with moment of silence
Annual Review of Ethics and Compliance Reporting Policy
November Regular Board Meeting
Annual CEO Performance Evaluation
December Regular Board Meeting
Review Key Performance Indicators (KPI) and Methodology for next
period
Cyber Security Review
Appoint NRECA Voting Delegates for NRECA Annual Meeting
Appoint CFC Voting Delegates for CFC Annual Meeting
Appoint NRTC Voting Delegates for NRTC Annual Meeting
Strategic Item or
Compliance Item
Reoccuring
or Ad-hoc
Reoccurring
Procedure
Reoccurring
Procedures
Reoccurring
Procedures
Compliance
Reoccuring -biennial
August Special Meeting
September Regular Board Meeting
Strategic
Compliance
Compliance
Strategic
Strategic
Ad-hoc
Reoccurring
Ad-hoc
Ad-hoc
Reoccurring
Ad-hoc
Compliance
Ad-hoc
September Regular Meeting
Reoccurring
Reoccurring
Ad-hoc
Compliance
Strategic
Compliance - Bylaws
Policy
Policy
Compliance
Strategic
Strategic
Strategic
November Regular Board Meeting
Compliance
Reoccurring
November Special Meeting of Committees
Strategic
Compliance - Ethics and
Compliance Reporting Policy
Compliance - CEO Performance
Evaluation Policy
Reoccurring
Strategic
Reoccurring
Strategic
Compliance - NRECA
Compliance - CFC
Compliance - NRTC
Reoccurring
Reoccurring
Reoccurring
Reoccurring
Reoccurring
Reocurring
Ad-hoc
Ad-hoc
Reoccurring
Reoccurring
Reoccurring
Reoccurring
Board
Meeting
Month
Packet Pg. 218