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Attachment E

Description of ERCOT Roles and Responsibilities

75

ERCOT's Description of Roles and Responsibilities within the Electric Market in Texas

Public Utility Commission of Texas (PUC) SUBST. R. §25.362(i)(2)(E) requires: "A descriptionof ERCOT's roles and responsibilities within the electric market in Texas, including systemreliability, operation of energy and capacity markets, managing transmission congestion,transmission planning and interconnection of new generating plants, and a description of howERCOT's roles and responsibilities relate to the roles and responsibilities of the transmission anddistribution utilities and retail electric providers and to the North American Electric ReliabilityCorporation and Texas Reliability Entity."

ERCOT BACKGROUND AND HISTORY

ERCOT, founded in 1970, is the independent system operator (ISO) for the electric power regioncovering 75 percent of Texas's land area and serving 85 percent of Texas load. Section 39.151of the Public Utility Regulatory Act (PURA), as amended by the 76a` Texas Legislature in SenateBill 7 (SB7) in 1999, assigns the following responsibilities to the independent organization forthe ERCOT Region:

(1) Ensure access to the transmission and distribution systems for all buyers andsellers of electricity on nondiscriminatory terms;

(2) Ensure the reliability and adequacy of the regional electrical network;(3) Ensure that information relating to a customer's choice of REP is conveyed in a

timely manner to the persons who need that information; and(4) Ensure that electricity production and delivery are accurately accounted for

among the generators and wholesale buyers and sellers in the region.

ERCOT's highest priority is to ensure reliable and secure transmission of electricity in theERCOT Region. ERCOT's primary responsibility is to facilitate reliable power grid operationsin the ERCOT Region by working with the region's Market Participants.

In 1996, in response to recommendations from industry participants made in conjunction withnew legislation and revised rules issued by the PUC, ERCOT's organization was restructured,and it began operating as the not-for-profit ISO for the ERCOT Region. Since that time,ERCOT's role in the Texas electricity marketplace has expanded in response to the restructuringof the electric utility industry mandated by SB7, which introduced competitive choice toelectricity customers in areas of Texas previously served by investor-owned utilities (IOUs).ERCOT plays a significant role in overseeing the competitive retail and wholesale electricitymarkets in the ERCOT region while ensuring secure and reliable operation of the interconnectedregional transmission grid. Following the mandates set forth in SB7, ERCOT assumedresponsibility for implementing the market structure, systems infrastructure, and businessprocesses to facilitate retail competition in ERCOT's electricity market.

As the single control area operator for the ERCOT Region, ERCOT oversees an electric gridconsisting of more than 550 generation units and 40,530 miles of high-voltage transmissionlines. While the actual ownership of the generation and transmission assets resides with their

76

owners, ERCOT, through its role as the ISO, is charged with maintaining Market Participantaccess to the regional transmission system, monitoring existing transmission facilities, andsupervising the transmission planning process to ensure the long-term reliability of the regionaltransmission grid. Market Participants in the ERCOT region must coordinate their activities withERCOT to transmit electricity through the regional transmission grid.

ERCOT is a membership-based 501(c)(4) nonprofit corporation with members in the followingMarket Segments: IOUs, municipally owned utilities (MOUs), electric cooperatives, independentgenerators, independent power marketers, independent REPs and consumers.

System Operations:

The ERCOT System Operators, working from the ERCOT Control Centers, have theresponsibility and authority to direct the real-time actions of all generating plant andtransmission line operators in ERCOT to ensure the stable and reliable operation of the BulkElectric System (BES) during both normal and emergency conditions. ERCOT is the only entityregistered with NERC to perform the functions of, Reliability Coordinator, Balancing Authority,and Interchange Coordinator in the ERCOT Region.

To accomplish these functions the primary activities performed are:

• Request and receive information required to continually monitor and direct the operationof the ERCOT BES to ensure its security and reliability in accordance with the ERCOTProtocols, Operating Guides, and North American Reliability Corporation (NERC)Reliability Standards.

• Operate the ERCOT BES 24 hours a day, 7 days a week utilizing advanced networkanalysis applications including State Estimator, Real Time Contingency Analysis, Real-Time and Study Mode Operations Power Flow, Voltage Stability Analysis and DynamicStability Analysis to continuously monitor the transmission lines and generation units inthe ERCOT interconnection to ensure security and reliability of the ERCOT system.

Perform security analyses on a Day-Ahead basis and manage congestion on a real-timebasis to ensure the ERCOT system is operated in such a manner that the outage of anysingle facility (Contingency) in the system will not cause the uncontrolled breakup of thetransmission system; loading of transmission facilities above their defined emergencyratings, which cannot be eliminated in time to prevent damage or failure; or operation attransmission voltage levels outside system design limits, which cannot be correctedthrough execution of specific, predefined operating procedures before voltage instability

or collapse occurs.

Review the Daily operations plan and calculate and post the allocated ResponsiveReserve, Regulation and Non-Spin Reserve Service obligations.

• Operate the Day-ahead Ancillary Service Market to ensure Up Regulation, DownRegulation, Responsive Reserve and Non-Spin Reserves capacity needs are met.

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• Run the Weekly Reliability Unit Commitment (WRUC), Day-ahead Reliability UnitCommitment (DRUC) and Hourly Reliability Unit Commitment (HRUC) to ensure theERCOT grid has sufficient generation capacity to resolve transmission congestion andmeet system load expectations.

• Calculate values necessary to deploy generation using Security-Constrained EconomicDispatch (SCED) every 5 minutes to minimize the use of Regulation and minimize thecost of energy.

• Receive all specified notifications from all Market Participants with regard to bids,generation control modes, routine adjustments, and equipment limitations or outages.

• Ensure compliance with the ERCOT Protocols and Operating Guides on identifiedtransfer limits.

• Implement Energy Emergency Alert(s) when conditions create a potential generationcapacity shortage. These actions may include all actions up to and including directing theshedding of firm load to maintain the integrity of the ERCOT system.

• Obtain and/or arrange to provide emergency energy overthe DC Tie(s) with other

Regions to prevent emergency operations within the ERCOT system.

• Issue appropriate operating condition notices, advisories, watches, emergency notices,and coordinate the reduction or cancellation of transmission maintenance outages, re-dispatch of generation, and request, order or take other action(s) that the System Operatordetermines is necessary to maintain safe and reliable operating conditions on the ERCOTsystem in accordance with ERCOT Protocols, Operating Guides, and NERC ReliabilityStandards.

• Manage the DC-Tie scheduling and inadvertent energy accounting for the five (5) DCTies ERCOT shares with the Southwest Power Pool (SPP) and Comision Federal deElectricidad (CFE).

Coordinate the ERCOT System Restoration (Black Start) Plan in the event of an ERCOT-wide power system failure. System Operators will implement the Black Start Plan anddirect the reconnection efforts of the islands established by restoration activities. TheSystem Operators coordinate the mutual assistance activities of the ERCOT participantsduring system restoration activities.

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Operations Support:

ERCOT performs many activities to assist ERCOT System Operators to solve real-timereliability issues. This involves development of Remedial Action Plans, Temporary OutageAction Plans and Mitigation Plans, as well as providing engineering support for control roompersonnel in the execution of operating procedures and analysis of operations.

Operations Engineers calculate and post day-ahead transmission system limits for publishing tothe ERCOT Market and use in the day-ahead unit commitment and energy market analyses. Theintent of ERCOT's day-ahead limit calculation is to set and enforce limits to prevent ERCOTfrom entering an insecure state in which the outage of a single facility ( it might be a singletransmission line or double-circuit transmission lines on the same structure) could lead to othertransmission facilities' overload or system instability.

Operations Engineers are responsible for responding to recurring transmission congestion inERCOT by verifying the following information with the Transmission owners within ERCOT:

Equipment Ratings

System Topology (when there is a discrepancy between Transmission Owner andERCOT analysis)

Review possible transmission operations that could mitigate congestion

Operations Engineers are responsible for the process for data-gathering, investigation,development, review, and distribution of reports for the ERCOT Reliability OperationsSubcommittee (ROS). These reports are as follows:

• ERCOT Monthly Operations Report

• Preliminary Energy Emergency Alert (EEA) Reports

ERCOT is responsible for identifying and monitoring System Operating Limits (SOL), whichhave the potential to be an Interconnection Reliability Operating Limits (IROL) as a result ofchanging system topology, configuration, or flows. IROLs could expose ERCOT to instability,cascading outages, or uncontrolled separations that adversely impact the reliability of the BulkElectric System. ERCOT must notify NERC and the Texas Regional Entity (TRE) within 72hours when a predetermined subset of System Operating Limits (SOLs), called potentialInterconnection Reliability Operating Limits (IROLs), have been exceeded.

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Operations Planning:

Operations Planning is intended to provide ERCOT system operators with a proper assessmentof the ERCOT system to ensure grid reliability needs are met. The major activities performedunder this program include near-term Load Forecasting, Wind Generation Forecasting, VoltageProfile Assessment, Resource Net Dependable Capability Assessment, and Stability Studies.

The Load Forecasting application uses historical observations and forecasts of meteorologicaldata to determine load demand in MW for future time periods. The ERCOT system is broken upinto eight weather zones, and forecasts are produced for each of these zones. The valuesproduced are the expected hourly average load for each zone looking from the upcoming hour toone week into the future ( 168 hours).

The Wind Generation Forecasting application provides MW load forecasts for both the aggregateERCOT system and for all the individual wind generation resources. Two values are provided aspart of each forecast for each hour for a rolling 48-hour period. Both of the values are hourlyaverage values. The first is a forecast of the most likely average MW value for that hour. Thesecond is an 80% level of confidence forecast. This means that the forecast is biased such that itis expected that the actual MW is greater than the forecasted value 80% of the time. This givesERCOT both a likely actual target and a conservative estimate of the MW output from the windgeneration resources.

The Voltage Profile Assessment is performed to meet ERCOT Protocol and NERC ReliabilityStandards requirements, which call for a voltage profile to be developed for the ERCOT region.ERCOT re-evaluates the voltage profile twice a year (or more often if necessary) to ensurereliable voltage control on the ERCOT system.

The Resource Dependable Capability Assessment is performed to ensure that the ERCOTsystems have the most accurate values for each resource's High Sustainable Limit (HSL),Leading Reactive Capability and Lagging Reactive Capability as required by the ERCOTOperating Guides.

Each season, between 400 and 450 resource HSLs are submitted to ERCOT by the QualifiedScheduling Entities (QSEs) representing the resources. ERCOT also conducts unannounced testsfor selected resources to be tested without prior notification to ensure that the resources can meetthe HSLs reported by the QSEs. If the resources cannot meet their HSL, ERCOT Protocolsrequire QSEs to lower the HSL to the value sustained in the Unannounced Test. This processensures that the total available capacity calculated in ERCOT systems is accurate.

Leading and Lagging Reactive Capability tests are conducted biennially as required by theERCOT Operating Guides. The results of these tests are assessed by ERCOT OperationsPlanning and, if accepted, are incorporated into ERCOT systems as necessary. This testingensures that ERCOT systems have the most up-to-date reactive capability curves so anyreliability studies performed are as accurate as possible.

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Stability Studies are performed as needed to ensure proper monitoring of the grid and to meetNERC Reliability Standards. ERCOT performs stability assessments to evaluate potential systemvoltage and inter-area oscillation issues under various system conditions. Voltage SecurityAssessment Tool performs voltage stability analysis for several areas within ERCOT to ensurethe reliable operation of the transmission network. The Transient Security Assessment Toolperforms dynamic stability analysis to maintain system reliability. The West - North TransferLimit is established and monitored on a designed interface between West Texas and the rest ofERCOT, and is used in real-time operations.

ERCOT evaluates whether a generating unit that announces suspension of operations orretirement or seasonal operation is needed to meet transmission reliability requirements andarranges Reliability Must Run (RMR) Service for any unit that is required for this purpose.

Outage Coordination:

The primary purpose of the outage coordination program is to determine if transmission andresource outages that are required for maintenance and operational reasons should be allowedwithout compromising reliability.

The program receives and processes more than 100,000 outage requests annually in accordancewith ERCOT and NERC reliability standards, protocols and procedures. ERCOT OutageCoordination processes requests to determine whether they contain all the required information,conducts security analysis studies of the ERCOT system, as appropriate, for the relevanttimeframe, and approves or rejects the requests.

Operation of Markets:

ERCOT's wholesale market operations activities include operating the ERCOT Markets thatmanage the commitment and dispatch of Generation and Load Resources, Ancillary Servicemanagement, and transmission network congestion management hedging through a combinationof biannual and monthly Congestion Revenue Rights (CRR) auctions, a voluntary Day-AheadMarket (DAM) for energy and ancillary services, a daily and hourly Reliability UnitCommitment process, and a Real-Time Market for energy dispatch in the ERCOT control area,which comprises 85% of the electricity customers in the State of Texas.

At a high level, the CRR Auction is an opportunity for the market to purchase and sellcongestion revenue rights on a monthly basis for months or years into the future. The Day-AheadMarket is a voluntary market for buyers and sellers of energy and Ancillary Services. It isexecuted 365 days a year for the next operating day to secure the Ancillary Services (AS)required to support power operations, and includes a voluntary energy market to procure andprice energy and hedging contracts for Real Time. During the Operating Day, the ERCOT Real-Time Market calculates and re-dispatches the on-line generation in ERCOT every five minutes toachieve a least-cost economic dispatch that is secured within the network transmissionconstraints of the power system.

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Congestion Revenue Rights Auction:

CRR Auctions are conducted on a monthly basis for the next delivery month, and twice a yearfor two years into the future. CRRs are financial instruments that result in a charge or a paymentto the owner when the ERCOT transmission grid is congested in the Day-Ahead Market andresults in price separation. CRRs may be used as either a financial hedge or a financialinvestment. When used as a locational hedge, a CRR locks in the price of congestion at thepurchase price of the CRR in the auction, to offset potential future price differences for energybeing injected at one location and withdrawn at another in the Day-Ahead Market. Whenpurchased as an investment, it may be used as a financial tool to speculate whether thecongestion rent will be greater than the purchase price. The main purposes of the ERCOT CRRmarket are to: (1) support a liquid energy market by providing tradable financial instruments forthe hedging of transmission congestion charges, (2) allow market participants to eliminate orgreatly reduce the cost uncertainties resulting from transmission congestion charges, and (3)encourage competitive energy trading, where the costs of congestion might otherwise be animpediment for procuring load.

CRR ownership may be acquired in four different manners:

(1) CRR Auction - ERCOT shall conduct monthly and biannual auctions to alloweligible CRR Account Holders to acquire CRRs. The auction also allows CRROwners an opportunity to sell CRRs that they hold.

(2) Allocations - ERCOT shall allocate CRRs (known as Preassigned CongestionRevenue Rights (PCRRs)) to eligible Municipally Owned Utilities (MOUs) andElectric Cooperatives (ECs) under ERCOT Protocols Section 7.4, Allocation ofPreassigned Congestion Revenue Rights.

(3) Bilateral Market - CRR Account Holders may trade Point-to-Point (PTP)Options, PTP Obligations, and Flowgate Rights (FGRs) bilaterally. PTP Optionswith Refund and PTP Obligations with Refund are not bilaterally tradable.

Bilateral trading may be done privately or through ERCOT. ERCOT shall

facilitate trading on the Market Information System (MIS) Certified Area ofexisting CRRs between CRR Account Holders, subject to credit requirements.ERCOT shall settle CRRs with the CRR Account Holder shown on ERCOT

records.(4) Qualified Scheduling Entities (QSEs) may bid and be awarded for PTP

Obligations in the DAM that are settled at the real-time price differences betweentwo locations, thus creating a locational hedge in real-time.

Day-Ahead Market:

The Day-Ahead Market (DAM) is a daily, co-optimized market in the Day-Ahead sequence for

clearing Ancillary Service capacity, CRRs, and forward financial energy transactions.

Participation in the DAM is voluntary and financially binding. DAM energy settlement is basedon DAM Settlement Point Prices that are calculated for Resource Nodes, Load Zones, and Hubsfor one-hour settlement interval using the Locational Marginal Prices (LMPs) from DAM. In

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contrast, the Real-Time energy settlements use Real-Time Settlement Point Prices that arecalculated for Resource Nodes, Load Zones, and Hubs for a 15-minute Settlement Interval.

To participate in the DAM, market participants can submit three-part supply offers for generationresources, Ancillary Service offers (from generation or load resources), DAM energy-only offers(virtual or physical), DAM energy bids (virtual or actual load), PTP Obligation bids (locationalhedge), self-arrangement of Ancillary Services (AS), current operating plans (COP), energytrades, capacity trades, and AS trades. These submissions can be made up to 14 days in advanceof the Operating Day and must be submitted by 10:00 hrs on the day prior to the operating dayfor consideration in the DAM. All transactions are subject to a credit check at 07:00 in the Day-Ahead Market timeline, and then credit is enforced on all remaining transactions prior to the startof DAM execution at 10:00. The DAM is a mixed integer optimization program that clears in theDay-Ahead the AS Capacity, CRR valuations, and energy markets. The program also includesco-optimization across both Energy and AS to consider the most economic solution for therequired AS and voluntary energy demand across the 24 hours in the Operating Day. DAMresults are normally published by 13:30 hours each day. With the exception of AS awards beingrequired to be scheduled on the awarded resource, all other awards are financially binding only.

One hour after DAM completes, but no earlier than 14:30, System Operations executes a Day-Ahead Reliability Unit Commitment (RUC) study to ensure that the ERCOT System has enoughResource capacity, including AS reserves capacity, committed in the right locations to reliablyserve the forecast Load on the ERCOT System, subject to transmission constraints. Anycommitments or decommitments of resources from this study are physically binding. In additionto the daily RUC study, ERCOT runs an hourly RUC that continues to study the balance of theday for reliability and can commit additional resources as necessary. In addition to energycapacity, if AS requirements increase or are undeliverable from a resource in the adjustmentperiod, ERCOT may open a Supplemental Ancillary Services Market (SASM) to procure thebalance of services needed.

Real-Time Market Dispatch:

Every five minutes the Real-Time Market and dispatch is performed by a Security-ConstrainedEconomic Dispatch optimization process (SCED) to achieve a least-cost economic dispatchconsistent with network transmission constraints and to satisfy the necessary power balance of

the system. The SCED uses only the Generation Resource Energy Offer Curves,incremental/decremental Energy Offer Curves, and Output Schedules submitted by the end ofeach adjustment period for an operating hour. ERCOT calculates a market solution and sends outresource base points (awarded output level for resource) that are needed to simultaneouslymanage energy balance and congestion every five minutes, or more often, as determined by theoperator. SCED uses a two-step methodology that applies market mitigation prospectively toresolve constraints for the current operating hour while also evaluating energy offer curves andoutput schedules to produce a least-cost dispatch of online generation resources to match Loadwith the on-line generation subject to network transmission constraints. Once the SCED marketis cleared, the SCED base points for each resource are telemetered to the market participant andall locational prices are publicly posted. SCED prices are calculated at least every five minutes

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and then rolled up into a time-weighted average as a 15-minute settlement interval point price forevery Resource Node, Load Zone and Hub.

Retail Operations:

ERCOT acts as the registration agent for Retail Electric Providers and provides a centralized hubfor retail transactions. Electronic Data Interchange (EDI) transactions for Load Serving Entity(LSE) relationship maintenance (Move In, Move Out, Switches, and Drop to Affiliate REP) aresubmitted by Transmission and/or Distribution Service Provider (TDSPs) and LSEs and areprocessed within the ERCOT ESI ID Registration System to establish and update ESI IDrelationship records. On a daily basis, the additions and changes to ESI ID relationship recordswithin the ERCOT ESI ID Registration System are processed into the ERCOT Data AggregationSystem.

Additionally, ERCOT is the designated program of the Texas Renewable Energy Credits tradingprogram.

Settlements Overview:

ERCOT's responsibility for settlement, billing and financial transfer ensures that electricityproduction and delivery are accurately accounted for among the market marticipants.

These responsibilities include receiving, retrieving and estimating energy production andconsumption data from all points within ERCOT, grouping the data by responsible marketparticipant, applying appropriate load profiles, loss factors, and unaccounted for energy (UFE)allocation mechanisms, and finally, producing the necessary billing determinants to settle themarket for each 15-minute interval. Meter data is submitted to ERCOT by transmission and/ordistribution service providers (TDSPs) via Texas Standard Electronic Transactions (TX SET) forpremises with standard Interval Data Recorder (IDR) or Non-Interval Data Recorder (NIDR)meters or Load Serving Entity (LSE) files for premises with advanced meters. Meter data forpremises designated as ERCOT Polled Settlement (EPS) meters are acquired via an MV-90system that polls the meters remotely. Defined estimation routines are used to estimateconsumption for ESI IDs that are missing actual usage data. Prior to each settlement run for anoperating day, the actual/estimated meter data is used in the meter data aggregation process andthen by the settlement system for the settlement process

ERCOT calculates payments and charges to QSEs and CRRAHs using the results of the DAM,RTM, CRR market activities, and the energy production and consumption. ERCOT settles RTMactivity, DAM activity, and CRR auction activity with registered CRR Account Holders and/orQualified Scheduling Entities, as applicable. A total of 70 charge types are utilized to bill theentities; these charge types are identified in ERCOT Protocols and are calculated whenever theidentified conditions occur. Each relevant charge type is paid and/or charged to a QSE orCRRAH as part of the market financial settlement processes. The charge types are identified inERCOT Protocols and are calculated whenever the identified conditions occur. The table belowprovides summary details regarding the various settlement statements and invoices.

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T

Invoice or

^ StatenientRecipient Frequency Post Tiining Payment Timing

ype

CRR CRR auction • CRRAHs With each lst business day 3`d bank businessinvoice Monthly after completion day after invoiceand Annual of a CRR auction posts (or next dayAuction (monthly and that is both

annual CRR business day andauctions are bank businessinvoiced day)separately)

CRR auction • QSEs (with Monthly lst business day 5th bank businessrevenuedistribution

Load) after RTM initial day after invoice

i istatement posts posts (or next daynvo ce for the last day of that is boththe relevant business day andmonth bank businessand day)

I 't business dayafter RTM finalstatement postsfor the last day ofthe relevantmonth

CRR balancing • CRRAH Monthly 1 St business day I 't bank businessaccounti

(due a after RTM initial day after the duenvoice shortfall statement posts date of the RTMrefund) for the last day of invoice that

• QSEs (with the relevant includes the RTMload) month initial settlement

statement for thelast day of themonth (or nextday that is bothbusiness day andbank businessday)

*payout tomarket only

DAM DAM • QSEs Daily 2"d business day n/astatement• CRRAHs after the

operating day

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I Invoice orTvpe i Statement

Recipient Frequency Post Tiniin g Payment Timing

DAMresettlement

• QSEs Ad hoc Ad hoc (on n/astatement . CRRAHs business day)

*Market noticerequired

DAM late feeinvoice

. QSEs Monthly 10^' calendar day 4th bank business• CRRAHs after the end of day after invoice

the relevant posts (or nextmonth (or next day that is bothbusiness day) business day and

bank business

RTM RTM initialsettlement

. QSEs Daily Operating day + 6day)n/a

statement oCR^Hs (or next businessday)

Moving toOperating day +5 effective5/1/2014

RTM finalsettlement

• QSEs Daily Operating day + n/astatement • CRRAHs 57 (or next

business day)

Moving toOperating day +55 effective5/1/2014

RTM true-upsettlement

. QSEs Daily Operating day + n/a

statement . CRRAHs 180 (or nextbusiness day)

RTMresettlement

• QSEs Ad hoc Ad hoc (on n/asettlement . CRRAHs business day)

statement *Market noticerequired

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I"Voice orType i Statement

Recipient Frequencv Post Timing Payment Timing

Default upliftinvoice

• QSEs Ad hoc Ad hoc (on 5th bank business• CRRAHs business day) day after the

*Market notice invoice posts (orrequired next day that is

both business dayand bank

RTM late feeinvoi

. qSEs Monthly 101' calendar da

business day)

4h bce• CRRAHs

yafter the end of

usiness dayafter invoice

the relevant posts (or nextmonth (or next day that is bothbusiness day) business day and

bank business

DAM Settlements& Invoice

. QSEs Daily Every ERCOT

day)

2°d business dayRTM • CRRAHs business day after the invoice

posts (or next daythat is bothbusiness day andbank business

MISC Miscellaneousi i

. QSEs Ad hoc Ad hoc (on

day)

nvo ce• CRRAHs business day)

Specified in themarket notice

*Market noticerequired

Managing Transmission Congestion:

The Congestion Analysis program is intended to provide information necessary to allow themanagement of transmission constraints through market mechanisms,on congestion management activities and to provide market reports

costs, and to identify near-term system and operationalimprovements that allow more efficient management of system constraints. The major activitiesof this program include:

• Competitive Constraints Testing• Congestion Analysis• Medium-Term Projected Assessment of System Adequacy (PASA) Projected Constraints• Reliability Must Run Studies• Special Protection System Studies• Congestion Revenue Rights Calculations• Residual Congestion Recommendations

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The determination of Competitive Constraints is conducted in compliance with Protocols Section3.19. This process is used to determine if there is sufficient competition to resolve a transmissionconstraint and if mitigation of energy offer curves for specific generation resources in the RTMis appropriate.

In performing congestion analysis tasks ERCOT staff provides monthly reports to the ReliabilityOperations Subcommittee (ROS) and the Wholesale Market Subcommittee (WMS). ERCOTstaff also assists in the facilitation of Congestion Management Working Group meetings. Thecongestion analysis staff works closely with ERCOT System Operations Staff to provide timelyresponses to Market Participant inquiries on congestion issues that occur during real-timeoperations.

The Medium-Term Projected Assessment of System Adequacy Report is a three-year projectionof the availability of resources. This report is required by PUC Substantive Rule §25.505(d)which states that ERCOT shall provide market participants with information to assess theadequacy of resources and transmission facilities to meet projected demand. The Medium-TermPASA Projected Transmission Constraints report is updated every month.

Pursuant to Protocol Section 3.14.1.2, Long-term Outage Notifications and Initiation andApproval of Reliability Must Run (RMR) Agreements, RMR studies are performed, upon receiptof a Notice of Suspension of Operations from a Generation Entity. RMR studies evaluate thereliability of the ERCOT system with the absence of the resource whose generation is proposedfor suspension. When RMR studies indicate that the resource is needed in order to operatereliably an RMR Agreement is established with the resource until system upgrades can becompleted which permit the exit of the RMR Agreement.

Special Protection System (SPS) is a reliability tool that allows ERCOT to take pre-plannedcorrective actions to provide acceptable system performance when abnormal system conditionsare detected. In analyzing SPSs ERCOT evaluates whether the SPS adversely impacts othertransmission elements in the system and if the SPS supplies the relief that it is intended toprovide. SPS guidelines are stated in Operating Guides Section 6.2.2.

Finally, ERCOT evaluates actual congestion on the system and determine whether thiscongestion is expected to be recurring, whether transmission upgrades have been planned toresolve it, whether additional upgrades are warranted, and whether interim solutions may beappropriate.

Network Modeling:

Network modeling provides cases that are used by engineers to simulate the electric grid for thepurpose of Transmission and Resource Planning, Energy and Market Operations, Day-AheadMarket, and CRR markets. For Transmission and Resource Planning, two sets of base cases arecreated each year in coordination with the TDSPs. These cases are updated quarterly. A separateprocess produces weekly cases for Energy and Market Operations and the Day-Ahead Market.

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The CRR Market relies on monthly and annual cases that are produced in a third process.Modeling information for all these models are drawn from the Network Model MaintenanceSystem (NMMS) which is maintained and validated by ERCOT staff.

Transmission planning:

Transmission Planning is one of ERCOT's core responsibilities, directly supporting the SB7requirements to maintain the reliability of the system and provide non-discriminatory access tothe system. ERCOT is also the only NERC-registered Planning Authority for the ERCOTInterconnection. The key parts of this program include:

• Annual Five-Year Transmission Plan• Regional Planning Group (RPG) Reviews• Long-Term System Assessment• NERC Compliance

The annual ERCOT Five-Year Transmission Plan is developed by ERCOT in conjunction withthe Transmission and/or Distribution Service Providers (TDSPs) and the Regional PlanningGroup (RPG). The plan addresses regionwide transmission needs and the planned improvementsto meet those needs for the upcoming five years. The ERCOT system is evaluated to determinetransmission system improvements that are required to meet NERC and ERCOT reliabilitystandards as well as improvements that can cost-effectively lower the overall cost of servingdemand in the ERCOT Region.

The RPG, led by ERCOT, is the forum that provides transparency and input into the planningprocess for all ERCOT stakeholders. This consensus-based group is open to all interested parties,including TDSPs, generators, marketers, consumer groups, environmental groups, landowners,governmental officials and PUC staff.

The RPG Charter and Procedures sets out the functions and procedures under which the RPGoperates. The RPG allows stakeholders to review and comment on all major transmissionprojects.

Except for minor transmission projects that have only localized impacts and projects that aredirectly associated with the interconnection of new generation, all transmission projects in theERCOT region undergo a formal review by the RPG to ensure an open and fair transmissionplanning process. This formal review process is facilitated by ERCOT and provides anopportunity for any interested party to comment or ask questions about proposed projects.

In addition, ERCOT performs an independent analysis of the need for major transmissionprojects that are submitted for RPG Review. The affirmative result of this review is formalendorsement of the project by ERCOT. This ERCOT Project Endorsement is intended tosupport, to the extent applicable, a finding by the PUC that a project is necessary for the service,accommodation, convenience, or safety of the public within the meaning of PURA §37.056 andPUC Substantive Rule §25.101.

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In each even-numbered year, ERCOT investigates the longer-term transmission needs of theERCOT System in the Long-Term System Assessment (LTSA). This scenario-driven assessmentlooks 10 or more years into the future to see what long-lead-time transmission projects may beneeded and to assess the cost-effectiveness of larger projects in lieu of numerous smallerprojects.

Many of the studies described above also are used to demonstrate compliance with NERCReliability Standards. ERCOT is registered as the Planning Authority for the ERCOTInterconnection and as such has a number of reliability standards with which it must demonstratecompliance.

Generation interconnection:

The key objective of this program is to provide non-discriminatory open access to thetransmission system, while maintaining the reliability of the system. All newly proposedgeneration projects of sufficient size that connect to the ERCOT transmission system must go

through the ERCOT generation interconnection process. This process facilitates theinterconnection of new generation units in the ERCOT region by assessing the transmissionupgrades necessary for new generating units to operate reliably. ERCOT performs a feasibilitystudy, also known as a security screening study, for each new generation project as required byPUC Substantive Rule §25.198. ERCOT also coordinates subsequent studies performed by thetransmission companies as the interconnection process progresses for each generation project.

Resource Adequacy Assessment:

ERCOT is responsible for collecting and maintain the data and formulating the reports that arenecessary for the market and regulators to assess the adequacy of resources on the ERCOTsystem. ERCOT performs several activities to support this responsibility:

• The Capacity, Demand and Reserves Report, which calculates reserve margins on anannual basis for the next 10 years;

• The Long Term Demand and Energy Forecast, which uses econometric and neuralnetwork techniques to forecast load, based on historical observations of load and weatherand forecasted economic conditions, for the next 10 years, for each of the eight weatherzones;

• The recently added Seasonal Assessment of Resource Adequacy, which is producedahead of each season to illustrate the range of potential resource adequacy scenarios;

• Special Studies related to resource adequacy, such as the various studies related to theimpact of new EPA regulations, weatherization, natural gas availability and drought;

• Reserve margin criteria studies, based on loss-of-load probability analyses performed todetermine the appropriate reserve margin minimum target to meet established reliability;

• The Medium-Term Projected Assessment of System Adequacy Report, which is a three-year projection of the availability of resources based on certain criteria. This report isrequired by PUC Substantive Rule §25.505(d).

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Compliance:

ERCOT is one of seven ISOs/Regional Transmission Operators ("RTOs") in the United States.ERCOT is unique from a reliability perspective due to its dual jurisdictional obligations. Prior tothe Energy Policy Act of 2005 ("EPAct 2005"), with the exception of certain Department ofEnergy ("DOE") reporting requirements, ERCOT was subject to the jurisdiction of the PUC forall matters, including reliability. With the passage of EPAct 2005, ERCOT became subject tofederal jurisdiction for reliability matters. Specifically, § 1211 of EPAct 2005 amended Part II ofthe Federal Power Act ("FPA") by adding §215, Electric Reliability. Section 215 establishes anenforceable reliability construct that applies to all owners, users and operators of the bulk powersystem. The ERCOT Compliance department is responsible for preparing and maintainingERCOT compliance with its reliability and security obligations to FERC, NERC and the PUC.

ERCOT's role in reliability oversight matters is linked to the following, each of which isdiscussed in more detail:

• The obligation to maintain reliability involves real-time monitoring of Protocolcompliance as part of its real-time operations function;

• Support obligations for the reliability and market oversight functions of the PUC, theTexas RE and the IMM;

• Oversight of market participant performance metrics under the ERCOT Protocols;• Reporting obligations under the NERC Reliability Standards;• Investigations related to NERC Compliance Monitoring and Enforcement Program

proceedings and obligation to respond to NERC inquiries related to such matters;• Investigation and reporting obligations under the NERC Events Analysis program;• Investigation and reporting obligations under the Department of Energy ("DOE")

requirement to report electric system emergencies and disturbances;• Investigations related to direct FERC oversight of reliability matters and obligation to

respond to FERC inquiries related to such matters.

PUC Rules:

Consistent with PURA, the PUC Substantive Rules require ERCOT to maintain the reliability ofthe electric grid. In addition to this general obligation, ERCOT supports the PUC's reliabilityoversight function. Section 25.503 of the PUC Substantive Rules governs the PUC oversightfunctions, which include markets and reliability. In addition to market oversight, Section25.503(a)(9) establishes that ERCOT shall have a role in overseeing compliance with reliabilityrelated rules (e.g. Protocols and Operating Guides) in the ERCOT region. Section 25.503(j) setsforth ERCOT's role in enforcing operating standards. Pursuant to this obligation, ERCOT isrequired to develop a process to monitor material occurrences of noncompliance with ERCOTprocedures. ERCOT is required to maintain records of all instances of material noncomplianceand to notify the PUC if the noncompliance is not resolved. The process to monitor compliancewith the relevant ERCOT rules is accomplished pursuant to the ERCOT Protocols and thereliability monitoring agreement between the PUC, the Texas RE and ERCOT ("ReliabilityAgreement").

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Section 8 of the ERCOT Protocols establishes performance metrics for certain reliability andmarket services. ERCOT is responsible for monitoring compliance with these metrics andreporting violations to the PUC and Texas RE in accordance with Section 8 and its obligationsunder the Reliability Agreement. ERCOT's administration of Section 8 necessarily requiresinteraction with third parties to investigate performance metric issues, and provides ERCOT thediscretion for requesting corrective action plans and relevant disqualification or suspension basedon performance and investigations.

NERC Compliance and Monitoring:

ERCOT is registered with NERC for the following functions:

• Reliability Coordinator (RC)• Balancing Authority (BA)• Planning Coordinator (PC)• Resource Planner (RP)• Transmission Service Planner (TSP)• Interchange Authority (IA)• Transmission Operator through Coordinated Function Requirement registrations (TOP

CFR).

ERCOT adheres to the NERC Reliability Standards, is registered and demonstrates complianceas outlined in the NERC Rules of Procedure and the NERC Compliance, Monitoring andEnforcement Program (CMEP). Compliance and Monitoring includes:

• Schedules Audits• Spot Checks• Self Reporting• Event Investigation (Event Analysis in field trial)• Self Certification• Enforcement Program and Settlements• Requests For Information (RFI)• Compliance Investigation (Cl formally CVI)• Organization Registration and Certification• Reliability Readiness Evaluation and Improvement

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Attachment G

Crisis Communications Procedures

93

ERCOT

Crisis Communications Procedures

Version 6.1

Nov. 5, 2013

ERCOT PUBLIC: NOT CONFIDENTIAL

94

ERCOT Crisis Communications Procedures ERCOT Public

Document Revisions

Date Version Description Author(s)

07/31/2007 0.01 First approved draft R. Drew/D. Roark

10/15/2007 0 02 Added sign-off page & updated staff D. Roark

03/24/2008 0 03 Updated staff R. Drew/D. Roark

04/07/2009 0.04 Annual update (primarily staff changes) D. Roark

5/1/2009 2.01 Revised EECP to EEA; updates to Appendix D pending D. Roark

7/6/2009 2.02 Appendix D edits D. Roark/A. Hale, A.

Apodaca

7/14/2009 2.03 Updated Load Shed Table D. Roark

March, 2010 3.10 Annual review/updates; revised communications matrix to D. Roarkreflect optional communications at Watch for 2500 MW

adjusted responsive reserves

9/10/10 3.20 Added notification of firm-load shed events; updated load D. Roarkshed table; added L Cobos contact information and otherminor edits to notification/press release templates

2/21/11 4.01 Revised to include post-Feb. 2 modifications regarding D. Roark

automated notifications via ENS; Updated news release

templates; Changed "Legal/Corporate Communications"to External Affairs

3/8/11 4.02 Added SOC and Board to all ENS notifications; inserted D. Roark"redlined" matrix; edited news release templates

6/10/11 4.03 Revised zonal protocol references to nodal protocols; D. Roarkinserted final matrix; web team procedures, call center

procedures, and other minor edits

7/12/11 4.04 Added C-5 - Grid Event Notification Lists Matrix; updated D. Roark

EEA templates to match PUC conservation tips; addednew emergency call treatment center diagram

10/10/11 4.05 Revised to include NPRR379 changes to EEA; updated D. Roarkstaff contacts, other minor edits

5/1/12 5.01 Added recommendations from internal audit; changed D. RoarkEILS to ERS (effective 6/1/12); added information aboutnew EmergencyAlerts list and revised Grid Event

Notification Lists Matrix and External CommunicationsMatrix for Energy Emergencies; redacted contactsappendix and other personal contact information in orderto change from "ERCOT Limited" to "Public"; redactedemergency call center diagram to protect confidentialnumbers; (Changes accepted after board review 5/15/12.)

6/17/12 5.02 Incorporated input from Board Communications Task R. SearcyForce, procedural updates and minor edits.

4/25/13 6 Update with updated matrix and minor edits to team R. Searcy

names, etc.

5/23/13 6.01 Minor revisions requested by ERCOT Board Chair R. Searcy

8/2/13 6.02 Cleaned up old charts R. Searcy

11/5/13 6.1 Update load shed table; review with storm drill R. Searcy

95

ERCOT Crisis Communications Procedures ERCOT Public

Table of Contents

1 Introduction ................................ 4......................................................................................2 Purpose ...........

........................................................................................................................ 5

3 Scope ........ ........................................................................................................................... 64 Policies/Principles . ............................................................................................................5 Communications Constituencies

.. 7......................................................................................... 8

6 Crisis Communications Team and Responsibilities .. ....................................................... 107 Crisis Communications Procedures .......................................... 12........................................

7.1 Activate Crisis Communications Procedur es ........................................................7.2 Take Immediate Action

12.........................................................................................

7.3 Communicate information about the Crisis12

..........................................................7.4 Bring Closure to Crisis

13..........................................................................................

7.5 Incorporate Learning13

.............................................................................................7.6 Energy Emergency Alert

13.......................................................................................

8 Long-term Crisis Communications Procedures14

.............. ..................................................9 Procedures for Crises with Lead-time

16...............................................................................

10 Procedures for Communicating with Federal Agencies1718....... ............................................

11 Definitions ................................................................................. 19........................................12 Maintaining the Procedures ............ ..................................................................................13 Training and Exercises

20......................................................................................................

Appendix A: Energy Emergency Alert21

.........................................................................................Appendix A-1 - Energy Emergency External Communications Matrix ..........................

2229

Appendix A-2 - EEA Notification Templates ..................................... 30.............................Appendix A-3 - EEA Incoming Call Hotline Messages .................................................. 40

Appendix B: Hurricane Communications Materials ...................................... 41...............................Appendix C: Crisis Communication Contacts ..............................................................................

Appendix C-1 - ERCOT Employee Contacts49

........ ..........................................................Appendix C-2 - Government Contacts

50.............................................................................

Appendix C-3 - Media Contact51

s ....................................................................................... 52Appendix C-4 - Market Participant Contacts ..................................... 53..............................Appendix C-5 - Grid Event Notification Lists Matrix ..................................................... 54

Appendix D: Procedures for Using the Public Website ................................. 55...............................Appendix E: In-Bound Calls Treatment .......................................................................................Appendix F: Black Start

57................................................................................................................ 60

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ERCOT Crisis Communications Procedures

1 Introduction

ERCOT Public

ERCOT is the organization responsible for ensuring the reliability and adequacy of the regionalbulk electric power grid for the majority of Texas. The ERCOT power grid encompassesapproximately 85 percent of the state's electric load and about 75 percent of the Texas land area.The ERCOT region covers most of Texas, including Houston, Dallas, Fort Worth, San Antonio,Austin, Corpus Christi, Abilene and the Rio Grande Valley. It does not include the El Paso area,the Texas Panhandle, Northeast Texas (including Longview, Marshall, and Texarkana), andSoutheast Texas (including Beaumont, Port Arthur and the Woodlands).

As the independent system operator for its region, ERCOT manages the scheduling of power onan electric grid consisting of more than 550 generation units and more than 40,800 miles of high-voltage transmission lines. ERCOT is a non-profit corporation regulated by the Public UtilityCommission of Texas (PUC) and subject to oversight by the Texas Legislature.

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ERCOT Crisis Communications Procedures ERCOT Public

2 Purpose

The purpose of the Crisis Communications Procedures is to ensure orderly and timelycommunication of information in the event of an unexpected, abnormal or critical situation thatthreatens the reliability of the regional electric grid; the operations of the ERCOT markets; or thesafety, health or security of ERCOT's employees or property. These procedures establish thecrisis communications framework for ERCOT to collect, coordinate and share emergencyinformation and system status with the Texas Legislature, the PUC, other Texas stategovernmental entities, market participants and stakeholders, local government, federalgovernment, and the media and public.

This document is not intended to address every contingency associated with crisis situations andthe associated operational issues and challenges. ERCOT has a separate Business ContinuityPlan, which addresses the numerous issues related to continuing its business operations during adisaster.

Due to the complexity of communications among these diverse groups, this document should beexpected to change periodically.

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ERCOT Crisis Communications Procedures ERCOT Public

3 Scope

The Crisis Communications Procedures will be implemented for incidents affecting largesegments of the bulk electric power grid; normal market operations; significant public health,safety or economic disruptions affecting ERCOT staff, property or constituencies; and any eventthat requires high-level management participation by government and the electric industry toeffectively and swiftly accomplish a return of the bulk electric power grid to normal operation.

The Crisis Communications Procedures deal only with crisis communications between ERCOTand appropriate regulatory, governmental and public-safety contacts. Other ERCOT documents,including the Business Continuity Plan, address broader crisis management procedures andpolicies, emergency response, disaster recovery and business continuity. Please refer to theEmergency Response Plan for additional information.

Additionally, this document refers to a crisis that affects the entire ERCOT region. Regional andlocalized electric reliability issues may be handled differently, as noted in more detail inAppendix A.

Except as noted, the steps outlined in these procedures are not governed by the ERCOTProtocols, but rather are internal ERCOT procedures for communications. The procedures shouldbe used in conjunction with the normal decision-making hierarchy of ERCOT and will notsupplant that decision-making process.

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