***Note to Readers:** This overview paper has been prepared by the
Transmission Service Liaison Group (TSLG) to provide an overview of the
conceptual framework for implementing Grid West's Basic Features,
specifically Market and Operational Design features. The information
provided in this draft is current as of the date shown below; however,
since design work is on going, this paper will be updated and modified
as TSLG completes additional work.*

*The preparation of the white papers described in this overview paper is
underway. As they are completed, the white papers will be released for
review and comment. Each white paper focuses on individual elements of
the overall design. This overview paper draft is being provided early to
allow readers to understand how the individual white papers fit into the
larger context of the Grid West Market and Operational Design.*

1.  **Grid West Market & Operational Design**

    1.  ***[Contents of the Overview Paper]{.underline}***

> This overview paper has been prepared by the Transmission Service
> Liaison Group (TSLG) to help interested parties understand TSLG's
> proposal materials. It explains what the TSLG has set out to
> accomplish and provides background information about the transmission
> problems and opportunities the TSLG proposals seek to address. It
> explains the relationships among the various subject areas and
> introduces the white papers that are the focus of the TSLG's current
> activities.
>
> Section 1 of this paper provides general background information.
> Section 2 explains how transmission providers currently manage
> contractual obligations and describes the operational challenges
> created by the present approach to transmission capacity management.
> Section 3 provides an overview of core elements of the TSLG's proposal
> for a new approach to providing transmission service. Section 4
> briefly describes the TSLG's work on the concept of control area
> consolidation, which is an optional feature of the Regional Proposal
> (in the sense that transmission providers that join Grid West may opt
> to consolidate their control areas or not). Section 5 identifies
> additional elements of the TSLG's proposal that are not covered in
> earlier sections of this paper. Appendix A provides summaries of all
> white papers and reference papers produced by TSLG to document the
> conceptual framework for Grid West's market and operational design.

2.  ***[TSLG's Assignment]{.underline}***

    a.  The TSLG's assignment is to develop a market and operational
        design framework for Grid West's Basic Features. The complete
        design work is divided into four layers, each with an increasing
        level of complexity.

    b.  The purpose of the first two layers is to develop a conceptual
        framework prior to Decision Point #2:

        i.  Layer 1 -- Major functions were defined in 2004.

        ii. Layer 2 -- Methodology, responsibilities, and costs are to
            be identified in 2005.

            -   A series of white papers, that address major design
                features, describe the conceptual framework. Figure 1.1
                shows the titles of the white papers, organized by the
                TSLG work modules with which they are associated. These
                white papers are introduced in Sections 3, 4 and 5 of
                this paper with summaries of the papers provided in
                those sections.

            -   The set of reference papers shown in Figure 1.1 cover
                general topics that are applicable to more than one of
                the white papers. The summaries of the reference papers
                are given in Section 5.

            -   A complete list of all the above papers with their
                summaries is also provided in Appendix A.

            -   A glossary of Grid West terms will also be provided.

    c.  Layers 3 and 4 will increase design detail to support Decision
        Points #3 and #4.

        i.  Layer 3 -- Will develop protocols for market rules, business
            rules, transactions, etc.

        ii. Layer 4 -- Will prepare tariffs, functional specifications,
            interface designs, detailed technology requirements, etc.

3.  ***[Market Monitoring]{.underline}***

    a.  The organizational form, authority and scope of activities for
        market monitoring are beyond the scope of TSLG's assignment.

    b.  However, in each of the white papers, potential market power
        issues are briefly discussed and prevalent mitigation strategies
        are identified.

    c.  The organization of formal markets for transmission rights,
        reserves and balancing energy will assist market monitoring
        activities.

![](media/image1.wmf){width="6.489583333333333in"
height="4.854166666666667in"}

> *[Figure 1.1]{.underline}. Chart of papers which cover the conceptual
> framework of market and operational design. Paper numbers are keyed to
> the list of paper summaries found in Appendix A.*

2.  **A Commercial Usage Model to Match Physical Reality**

    1.  ***[Getting Started]{.underline}***

        a.  The function of the transmission system is energy delivery
            from generation to load, including the ability to reliably
            serve load when contingencies occur either because of loss
            of generators or loss of lines within the transmission
            network.

            i.  Reliability aside, the value of the transmission
                system's delivery capacity is based on the value of the
                resources it can deliver. This is a reflected value
                rather than a direct value. Generation doesn't compete
                with transmission; rather, remote generation uses
                transmission to compete with local generation.

            ii. The value of transmission in forward periods (i.e. from
                day-ahead to years ahead) is based on the market
                participants' individual perceptions of the value of
                energy at the time of delivery in the future.

        b.  The interconnection of utilities provides both reliability
            and economy.

            i.  Transmission systems began with simple arrangements -- a
                line was built from a generator to a load. In the West
                much of that transmission initially was from remote
                hydro resources to either cities or mining centers.[^1]

            ii. There was an early recognition of opportunities for
                improvements in reliability and for obtaining economic
                savings if systems were interconnected.

            iii. Whenever an interconnection of AC systems occurs, a new
                 joint system is created. Such a multi-owner regional
                 system is by nature a single system electrically.

                 -   All the generators in an AC network are
                     synchronized, i.e., they all operate at the same
                     frequency, and because of governor action, they
                     respond jointly to maintain standard frequency when
                     there are changes in load or loss of generation or
                     transmission.

                 -   Power flow distribution in the network is
                     free-flowing and governed by system physics, i.e.,
                     the system topology, line impedances, and the
                     location of generation and load.

                 -   The ability to alter flows without changing the
                     pattern of generation injections is very limited.

            iv. A single system with multiple owners can create what has
                been called the "problem of the commons" -- that is, the
                temptation for each user to maximize its own benefits
                from a shared resource without regard for the
                detrimental effects on other users.

                -   This problem of the commons is complicated by the
                    fact that multiple owners have different levels of
                    investments made at different points in time, which
                    leads to different perceptions about each owner's
                    appropriate usage share in the combined system.

                -   Over the time, a set of usage rules developed to
                    define each owner's share of the jointly created
                    transmission capacity of the system. However in
                    recent years there has been increasing concern that
                    the current set of usage rules is inadequate.

    2.  ***Do We Need a New System Usage Model?***

        a.  Today, transmission owners provide transmission services
            using an approach that is known as the "contract path"
            model. The base assumption of the contract path model is
            that separate owners can act independently. However, once
            interconnections began, this was never really true. As
            explained in more detail in Section 2.3, the contract path
            model was workable when it was first adopted because the
            transmission network was simpler (fewer interconnections)
            and there as sufficient "cushion" in the system to
            compensate for the mismatches between the way the contract
            path model assumed energy would flow (along the "contract
            path") and how energy actually moves across the system.
            These mismatches have come to be called "loop flow," which
            is explained in Section 2.4 below

        b.  The contract path approach is becoming less and less
            workable because the system has run out of "wiggle room".
            The methods used transmission providers to manage the
            contract path model (described in Section 2.5 below) are not
            as effective as they need to be, because the contract path
            model does not account for actual power flow effects.

        c.  A new and practical commercial service model of system usage
            is needed that will align transmission right issuance and
            scheduling with the physical realities of power flow in the
            transmission system.

        d.  To meet this objective of the Regional Proposal, TSLG has
            developed for a flow-based methodology (described in Section
            3 of this paper) that recognizes that the actions of each
            transmission user affect all other transmission users to a
            greater or lesser degree based on system physics.

    3.  ***The Challenges of the Existing Contract Path Usage Model***

        a.  During the summer of 2003, the Regional Representatives
            Group (RRG) developed a list of problems and
            opportunities[^2].

            i.  The contract path model of system usage was identified
                as a significant factor in underutilization of
                transmission capacity.

            ii. An opportunity exists to develop improved usage rules
                that allow existing capacity to be better utilized while
                still maintaining system reliability.

        b.  The contract path model is a simple "transportation" model.

            i.  For commercial purposes, transmission is assumed to be
                provided, and power is assumed to travel (or flow), on
                specific lines as if MWs were cars on a highway network.

            ii. This simplifying approximation was acceptable when the
                pattern of interconnections was fairly simple and there
                was surplus capacity in the transmission system.

            iii. However, this simple model has been retained past its
                 useful life, as described in Section 2.4, because of
                 its apparent simplicity and because of uncertainty
                 about the outcome when converting existing obligations
                 from one usage model to another.

        c.  The mismatch between the simple contract path and physical
            reality grew with the rapid growth of the system after World
            War II.

            i.  In the 30 years after World War II there was a burst of
                transmission construction.

                -   Canada and the Pacific Northwest were tied to
                    California by the lines that make up the elements of
                    the Pacific Interties.

                -   Transmission was strengthened within the greater
                    northwest as interior hydro and coal-fired resources
                    were developed.

                -   Ties were closed at Glen Canyon and in the Four
                    Corners area that connected Arizona and New Mexico
                    to Colorado and Utah (and from them to the greater
                    Northwest).

                -   Transmission was built to import coal-fired
                    resources into California from Arizona and New
                    Mexico.

            ii. Around 1970, the completion of the major
                interconnections described above "closed the loop" and
                gave the Western Interconnection its current system
                topology. Disputes quickly arose among the owners
                operating different portions of the transmission system
                because of inherent mismatch between actual system flows
                and the contract path model. This mismatch was dubbed
                *"loop flow"*.

        d.  Loop flow is the reality that belies the fiction that each
            path owner can act independently of other operators. Years
            have been spent in a fruitless debate over who the loop flow
            culprits are, when the real culprit is a commercial use
            model that doesn't square with reality. The example
            described in Section 2.4 demonstrates this inherent flaw in
            the contract path model.

        e.  Current approaches to loop flow management force
            inefficiency into system operations. In order to protect an
            owner's independent use of its share of system capacity,
            limits are placed on other owners' use of their own
            facilities. These limitations endeavor to protect system
            reliability, however because they are made *a priori*, they
            lead to underutilization of transmission system capacity.
            The contract path model provides has no reasonable economic
            means for transferring usage rights between owners as
            transmission user needs change.

        f.  An added problem with loop flow is that it cannot be
            predicted in advance under today's commercial arrangements.
            As a result, when loop flow problems occur in real-time,
            operators must use non-economic adjustment measures, i.e.,
            the curtailment of schedules, to correct path overloads.
            This is not particularly effective, but it is the only tool
            available to operators today.

    4.  ***A Loop Flow Example***

        a.  Under the contract path usage model, power is assumed to
            flow on an identified path as shown in Figure 2.1a. This
            example shows an injection made in system T with a
            withdrawal in system R. The transaction is scheduled through
            system S. The contract path is defined by the ownership of
            the contracting systems: R, S and T. Power is assumed to
            flow only on the facilities of these three owners.

        b.  The actual power flows on all the parallel paths based on
            system physics as shown in Figure 2.1b. The incremental
            effect of the injection in system T with a withdrawal in
            system R affects every line in the system. Lines with the
            lowest impedance see larger changes in flow (typically the
            higher voltage lines).[^3] The difference between actual
            flow and scheduled flow (contract path flow) is deemed to be
            "loop flow."

![](media/image2.wmf){width="6.027083333333334in"
height="4.552083333333333in"}

1.  

> [Figure 2.1a]{.underline}. An assumed contract path power flow over
> the facilities owned by systems R, S and T.

![](media/image3.wmf){width="5.96875in" height="4.4847222222222225in"}

[Figure 2.1b]{.underline}. A schematic representation of the actual
power flows associated with the contract path flows shown in Figure
2.1a.

c.  Loop flow is evaluated as the difference between the scheduled flow
    (i.e., the assumed contract path flow) and the actual flow. If the
    injection and withdrawal shown in Figure 2.1a is 100 MW, the
    contract flow through System S is 100 MW. If 60% of the injection in
    T moves through system S, then the actual flow through S is 60 MW.
    (The 60% ratio is called a Path Utilization Factor or PUF.) The loop
    flow in system S is then -40 MW, i.e., the actual flow of 60 MW
    minus the contract path flow of 100 MW. The 40 MW not flowing
    through system S, will be measured as actual flow moving through
    Systems P, V and U, although these latter three systems will have no
    matching schedule for those flows, so the 40 MW will be identified
    as loop flow or unscheduled flow by P, V and U.[^4]

    1.  

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5.  ***Efforts to Mitigate the Problems of the Contract Path Model***

    a.  Because simple contract path usage rules among owners impose
        unexpected costs,[^5] adjustments to the contract path model
        have been made to mitigate the effects of loop flow.

    b.  When transmission systems were expanding rapidly prior to the
        1980's, there was a tendency to build capacity ahead of need.
        Surplus capacity tends to mask the impact of actual flow to
        schedule flow mismatch, making it more tolerable.

        i.  Building ahead of need occurred in part because transmission
            line investments are "lumpy", i.e., you get the whole
            capacity of a transmission line when the line is energized,
            not some the capacity you need at the time.

        ii. Because the system was growing quickly, the extra capacity
            from a project would be needed in one or two years to move
            additional generation, so the economic burden of extra
            capacity was small.

        iii. These conditions no longer apply. System load is growing
             slowly. New generation tends to be gas fired, may well be
             owned by a non-utility entity, and located close to load
             and until recently. Little new transmission investment has
             been built in the past 15 years, and public resistance to
             transmission line siting is much more vigorous than it was
             20-30 years ago.

    c.  Even with surplus brought into early system by the construction
        effects, there were still many hours when the presence of loop
        flow created operational problems; As a result there was clear
        appreciation of the need to recognize (at least in part) the
        effect of the actual flows on the major parallel paths in the
        Western Interconnection. That need led to simultaneous ratings
        of parallel paths.

        i.  Simultaneous path ratings provide an approximate, flow-based
            division of system capacity between parallel paths.

        ii. While the simultaneous ratings nomograms[^6] provide bounds
            for operations, they do not provide a way of determining
            what operating point is "best".

        iii. In order to protect independent use by each path owner, the
             scheduled use of a path must be limited to the path rating
             even if actual flow is below the rating. At the same time,
             actual flow also must be limited to the path rating, even
             if the schedule was below the path rating.

        iv. The requirement to abide by this dual constraint causes
            capacity to go unused. The full system may be capable of
            moving more energy, but there is no way to enable heavier
            use on one owner's system if the owner of the parallel path
            is to be able to independently exercise its "share" of the
            simultaneous rating.

        v.  While the simultaneous rating process has reduced disputes
            among the owners, it has not resolved the underlying
            problem.

    d.  Another mitigation measure taken over the past 20 years is the
        installation and coordinated operation of phase shifting
        transformers[^7] to partially regulate loop flow.

        i.  Because the range of such devices is limited, they can only
            reduce loop flow but not eliminate it.

        ii. Their operation is not without cost; altering system flows
            by increasing phase angle also raises system losses.

        iii. As with path rating, the consequences of the mismatch
             problem are mitigated but not resolved.

    e.  The difficulty of reconciling the contact path mismatch with the
        realities of system physics will continue to increase:

        i.  There has been limited transmission construction over the
            past decade, yet network usage continues to grow. The
            combined effect reduces the slack in the system that
            previously made tolerable the mismatch between scheduled and
            actual flows.

        ii. New construction will only make network topology more
            complex and increase the number of places where the mismatch
            between actual flows and scheduled flows creates operational
            problems.

        iii. Passage of the Energy Policy Act of 1992 opened wholesale
             market access to the transmission system and increased the
             number of transactions the network needs to accommodate.

        iv. The addition of new generation has become difficult,
            especially for remote resources like wind generation.

            -   Available transmission capacity is in short supply when
                measured using the contract path usage model.

            -   However, studies of rated paths show that actual flows
                approach rated capacity in a relatively few number of
                hours of the year.

6.  ***[The Need for a Flow-based Usage Model]{.underline}***

    a.  As the preceding sections demonstrate, the old contract path
        model is not an effective tool for making best use of the
        transmission system.

    b.  To address the problems inherent in the contract path model, a
        flow-based methodology is needed. This need is the major driver
        behind the development of the Grid West proposal described in
        Section 3 below.

    c.  The base assumption of the contract path model, that separate
        owners can act independently, is untenable.

        i.  The modifications of the contract path model described above
            trim owner independence to a degree, but they offer no
            systematic, simultaneous approach to deal with actual flow
            effects.

        ii. The establishment of the Pacific Northwest Security
            Coordinator (PNSC) was a first step to looking at the
            combined real-time effects of system usage for the Northwest
            Power Pool control areas; however, the commercial model used
            for scheduling remains unchanged.

        iii. A structural change is needed, namely adoption of a
             flow-based methodology, to reconcile the commercial model
             with system physics, thereby recognizing the effect that
             the actions of each transmission user has on all other
             transmission users.

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3.  **The Flow-based Injection/Withdrawal Model**

    1.  ***Why is the Proposed Flow-based Model Better?***

        a.  A good commercial transmission model must align usage with
            physical realities, and it must be practical to
            implement.[^8]

            i.  The Grid West proposal for an Injection-Withdrawal model
                meets these criteria.

                -   It is consistent with POD/POR designations in
                    pre-existing transmission rights.

                -   It does not require the user to be a network expert.

                -   It is adaptable as the network changes.

            ii. To implement a single system injection-withdrawal usage
                model, a single manager of transmission system capacity
                is needed -- a single "gatekeeper" for use of system
                capacity.

                -   The capacity manager makes evaluations of existing
                    commitments and future use based on a grid-wide,
                    flow-based examination of the whole system as an
                    integrated regional network.

                -   While the governance of the entity charged with the
                    capacity management function must be responsive to
                    regional needs, the capacity manager must at the
                    same time be independent of the market participants
                    and not have a stake in market outcomes.

                -   Grid West is designed to meet this need for a
                    capacity manager for the region's transmission
                    system capacity. Grid West's function is analogous
                    to the function of an air traffic controller
                    managing usage of shared air space.

    2.  ***[Pre-conditions for Adoption a New Flow-based
        Model]{.underline}***

        a.  New services should be made available to make better use of
            the system.

        b.  The pre-existing transmission rights are preserved and can
            be used as they were in the past.

        c.  The implementation of the new model should avoid known or
            foreseeable market power problems and not create gaming
            opportunities.

        d.  There needs to be a reasonable and reliable transition path
            from today's practice to putting the new model into
            operation that also does not preclude the ability to make
            adaptations as system needs change in the future.

    3.  ***[Overall Features of the Grid West Flow-based
        Model]{.underline}***

        a.  Pre-existing obligations and agreements are unchanged in
            order to preserve pre-existing transmission rights. Only
            voluntary choices made by the right holders will alter their
            current rights.[^9]

        b.  A flow-based methodology with injection and withdrawal
            rights is adopted using a central administrator (Grid West)
            to manage the use of transmission capacity and to recognize
            the "one-system" (i.e. flow-based) reality of the regional
            system.

        c.  One-stop shopping for transmission services across the
            network is implemented through Grid West which will include
            transmission planning, capacity expansion and a single queue
            for long-term transmission service requests (one year or
            longer).

        d.  Transmission right reconfiguration services are implemented
            to enable better access to available capacity. These
            services combine release of capacity by transmission right
            holders with Available Flow Capacity (AFC)[^10] to provide
            wider trade in transmission rights. This improves access to
            short-term services (from hourly service for the next
            operating day up to service for a full year).

        e.  Voluntary consolidation of control areas using a day-ahead
            reserve market and a real-time balancing market is enabled,
            consistent with the Regional Proposal.

        f.  A staged implementation will be used for building up Grid
            West's Basic Features. The implementation plan will allow
            functionality to be increased over time with a cycle of
            testing, user training and successful operation. The process
            will be repeated each time new features are added. This has
            proven to be a successful, cost-effective approach compared
            to a "big bang" start with all features at the outset.

    4.  ***[Providing Transmission Service]{.underline}***

        a.  A transmission service framework has been developed that
            will allow the implementation of the flow-based methodology
            while leaving in place the pre-existing obligations and
            agreements of the Transmission Owners.

            i.  This is not a wholesale change in the provision of
                transmission service, but rather an incremental change.

                -   Because the pre-existing rights remain in place the
                    effect on the overall market will be quite modest.

                -   The change will better account for existing
                    commitments as rights are issued and right trading
                    is enabled.

            ii. Transmission users with pre-existing rights may continue
                to use their rights as they have in the past.

                -   The contracts that establish such rights will
                    continue to define the rights granted and the
                    limitations imposed.

                -   The implementation of the Grid West flow-based model
                    will not force any change in pre-existing agreements
                    and obligations.

                -   The holders of pre-existing rights will have the
                    option of using Grid West's broader transmission
                    services or continuing to take transmission service
                    as defined by their pre-existing contracts.[^11]

            iii. The proposed transmission service framework has two key
                 aspects:

                 -   The transmission service structure and

                 -   The transmission tariff structure.

        b.  The Grid West transmission service structure.

            i.  Grid West will offer Regional Network Service (RNS), new
                suite of services that will allow users to obtain
                transmission rights to schedule energy across the Grid
                West network. This service suite includes:

                -   Reconfiguration Services.

                -   Capacity Expansion Service.

                -   Scheduling Services.

            ii. To qualify for RNS a user must meet the System Access
                Requirement (SAR). The SAR verifies that a transmission
                customer is making a contribution to recovery of the
                system's fixed costs (i.e., the Transmission Owners'
                Revenue Requirements) that is appropriate for that
                transmission customer's situation.

                -   Load serving entities:

                    -   Where pre-existing rights cover an entity's full
                        load, the SAR is met. This allows the entity to
                        use RNS to release unused rights for sale or to
                        obtain rights to reach new resources not covered
                        by their pre-existing rights.

                    -   Load not covered by pre-existing agreements will
                        pay a load based rate to cover such load, thus
                        making RNS available to the entity.

                -   Generators:

                    -   The SAR is met by paying for interconnection
                        with the system.

                    -   Those with pre-existing rights maintain those
                        rights by continuing to pay the contract charges
                        for the agreements that grant those pre-existing
                        rights.

                    -   Additional transmission rights can be obtained
                        using RNS.

                -   Marketers:

                    -   Marketers without generation or load must meet
                        the technical and credit standards common to all
                        users of RNS, but have no other intrinsic
                        obligation.

                    -   If they have pre-existing rights, like
                        generators, they maintain those rights by paying
                        the contract charges for the pre-existing
                        agreements.

                    -   Additional rights may be obtained using RNS.

                -   Exports:

                    -   An export from the Grid West system, whether
                        made by a load-serving entity, a generator or a
                        marketer, will be treated as a load at the point
                        where the export occurs.

                    -   The exporter must either have pre-existing
                        rights to cover that export "load" at the point
                        of export or pay a Grid West load based rate to
                        cover the export "load".

            iii. Regional Revenue Requirement Adjustment (R3A)

                 -   When Grid West commences operation, Transmission
                     Owners will no longer issue transmission rights.

                     -   The revenues associated with pre-existing
                         long-term transmission agreements will continue
                         to be paid to the Transmission Owners according
                         to the terms of those agreements.

                     -   Revenues for short-term firm and non-firm
                         service currently received by Transmission
                         Owners will no longer exist because
                         Transmission Owners will not be offering new
                         transmission service. Short-term and non-firm
                         services will be replaced by IWRs purchased
                         using the Reconfiguration Services.

                     -   Transmission Owners' loss of the short-term
                         firm and non-firm revenues is, therefore, a
                         cost associated with offering RNS.

                 -   The R3A will be a charge made to all parties who
                     choose to use RNS.[^12]

                     -   Grid West's sales of AFC through the
                         Reconfiguration Service will recover part (and
                         perhaps most) of the revenue that was
                         previously recovered by the Transmission Owners
                         sale of non-firm and short-term firm
                         transmission service.

                     -   The R3A will cover the net cost of offering
                         AFC: any administrative costs associated
                         uniquely with RNS markets and the residual lost
                         revenue from short-term firm and non-firm sales
                         not recovered by sales of AFC.

                     -   The R3A could also be zero if AFC sales fully
                         offset the lost non-firm and short term
                         revenues and RNS specific costs. Any surplus
                         could be used to reduce other Grid West costs,
                         to reduce the Company Rates of the Transmission
                         Owners, etc.

*\[Drafting note to readers: The following information on tariff
structure is based on the Module 1 work done during 2004 Layer 1 design
work. While it is the best information currently available, there will
be changes in this section as Layer 2 work better defines the tariff
structure and clarifies the relationships among the Transmission Owners,
Transmission Customers, and Grid West.\]*

c.  The transmission tariff structure.

    i.  The above transmission service structure will be implemented
        through the issuance of a set of tariffs.

        -   Pre-existing rights will continue be covered by the
            transmission tariffs and contracts under which they were
            established by the Transmission Owners.

        -   New services will be covered by a combination of a Grid West
            Tariff and Transmission Owner Tariffs.

    ii. The Grid West Tariff[^13] will cover:

        -   General provisions to cover requests for transmission
            service, planning and capacity expansion, scheduling, the
            recovery of Grid West's costs through a Grid Management
            Charge, etc.

        -   Transmission interconnections:

            -   Interconnection requests will be covered in provisions
                in Transmission Owner Tariffs.

            -   Grid West will provide coordination of interconnection
                requests and dispute resolution for transmission
                interconnections.

        -   RNS -- rules for satisfying the SAR for load (including
            exports) not covered by pre-existing contracts, auction
            market rules, the R3A, etc.

        -   The Company Rates applicable to additional loads (i.e., load
            not under a pre-existing arrangement, including exports).

            -   A Transmission Owner may choose to have its Company Rate
                included directly in the Grid West Tariff, or

            -   A Transmission Owner may choose to have the Company rate
                included by reference with the Transmission Owner's
                Tariff separately filed and approved.

    iii. Grid West will issue new transmission rights as Injection
         Withdrawal Rights (IWRs).

         -   Long term IWRs will be issued under the Capacity Expansion
             Service whether from existing AFC or based on new AFC
             created by system expansion.

         -   Reconfiguration service will issue IWRs for as long as one
             year and as short as one hour.

         -   Residual AFC will be made available from the end of the
             day-ahead process until the cutoff to real time on a first
             come-first served basis.

d.  The white papers dealing with provision of transmission service are:

    i.  ***[Regional Planning & Capacity Expansion White
        Paper]{.underline}*** -- Describes the regional planning process
        to be facilitated by Grid West and the mechanisms for capacity
        expansion. Grid West will develop an open transmission planning
        process that examines expansion needs from a single system
        perspective, tests for transmission adequacy and considers
        non-transmission alternatives to meeting system needs. The
        capacity expansion service will deal with requests for long-term
        service requests (greater than one year). If capacity is not
        available to meet the request, the capacity expansion service
        enable market driven transmission projects to meet requests. It
        also provides for expansion backstops for maintaining existing
        transfer capability and meeting transmission adequacy standards.

    ii. ***[Tariff Administration White Paper]{.underline}*** --
        Describes the provision of transmission service through the Grid
        West Tariff and the related Transmission Owner Tariffs. It
        describes the roles of Grid West, the Transmission Owners and
        the transmission customers, and it provides discussion of issues
        related to pre-existing contracts, such as load growth, contract
        termination or roll-over, etc.

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5.  ***[Trading Transmission Rights]{.underline}***

    a.  [The reconfiguration concept]{.underline}.

        i.  The challenge of an injection-withdrawal model is how to
            enable trade rights among transmission right holders.

        ii. Trading rights bilaterally is limited to transactions in
            which the buyer desires the use of rights that are identical
            to those held by the seller.

            -   This means that independent trading requires a
                one-to-one match of injection and withdrawal points.

            -   Exact matches between buying and selling parties are
                unlikely, so such trade is limited.

        iii. To overcome this limitation, the Grid West proposal
             includes a Reconfiguration Service that allows transmission
             right holders to sell rights between one set of points and
             buy rights between a different set of points at the same
             time. This ability to reconfigure rights is made possible
             by Grid West role as the single "gatekeeper" for issuance
             of all new transmission rights in the Grid West Managed
             Transmission System

        iv. The Reconfiguration Service is based on a central auction of
            short-term transmission rights conducted by Grid West.

            -   IWRs released to the auction increase AFC on specific
                flowgates.

            -   Requests made can now be granted by using the combined
                AFC (both latent and released).

            -   Trade no longer requires a one-to-one match of injection
                points and withdrawal points.

![](media/image4.wmf){width="6.192361111111111in"
height="4.220138888888889in"}

> [Figure 3.3.]{.underline} An example of IWR reconfiguration for an
> offer of AB.

v.  An example of IWR reconfiguration is shown in Figure 3.3.

    -   *[Situation]{.underline}:*

        -   Party X holds an IWR from A to B of 100 MW that it will not
            be using next month.

        -   Party Y wants to purchase an IWR from C to D for 200 MW that
            for next month.

    -   *[Without Reconfiguration Service:]{.underline}* Since the
        points of injection and withdrawal for the AB right do not
        match, those of the CB right requested, no direct trade of
        rights is possible.

        -   Both have different effects upon the constraining flowgate
            that for this example is within the ownership boundaries of
            V.

        -   The PUF for an AB injection-withdrawal pair is 30%, that
            is, for a 100 MW schedule, there will be an incremental
            increase on flow of 30 MW on the constraining flowgate.

        -   The PUF for CD is 20%.

    -   *[With Reconfiguration Service]{.underline}*: Using the
        Reconfiguration Service a trade can be affected.

        -   Party X offers its 100 MW AB for release (sale), which
            makes the AFC on the constraining flowgate 30 MW (PUF~A-B~ x
            Offer).

        -   Party Y bids to buy 200 MW CD which would require 40 MW of
            AFC on the constraining flowgate.

        -   Y's full request cannot be satisfied, but 30 MW is
            available, so a 150 MW CD IWR can be issued. (AFC /
            PUF~C-D~)

        -   Without the trade, the capacity held for X's use would have
            gone unused, yet there was no way for such a trade to have
            occurred on a bilateral basis.

        -   Note that the MWs for the two IWR are different because of
            the impact of each IWR on the constraining flowgate, which
            shows another difficulty of the one-to-one trading
            restrictions that must be in place without a reconfiguration
            market.

    -   In actual practice, many offers to release and bids to buy will
        happen simultaneously. The auction software that enables
        reconfiguration trading uses a power flow algorithm that can
        simultaneously award IWRs while keeping all subscriptions within
        AFC limits.

    -   IWRs awarded in an auction are defined by the Grid West tariff.
        The nature of released (sold) rights of whatever vintage or
        source has no impact on the characteristics of an IWR.

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b.  [Addressing Scheduling Flexibility]{.underline}.

    i.  A Day-Ahead Redispatch feature was included in the Regional
        Proposal[^14] as a Basic Feature of Grid West.

    ii. The purpose of the day-ahead redispatch was to enable greater
        use of the transmission system by getting advance scheduling
        commitments.

    iii. Major difficulties were encountered in attempting to design
         such a  day-ahead redispatch:

         -   Since participation would be voluntary, only some schedules
             would be constrained by the day-ahead redispatch, and
             schedule changes made after the redispatch pursuant to
             pre-existing contract provisions could undo any
             optimization achieved by the day-ahead redispatch.

         -   Measurement and settlement of committed schedules would be
             difficult because not all of them would be settled in the
             same balancing market, i.e., some within the CCA and some
             in non-CCA control areas. 

    iv. When Day-Ahead Redispatch was revisited after the
        reconfiguration service had taken shape, it became clear that
        the desired effect of allowing parties to release a portion of
        their scheduling flexibility (i.e. commit to all or a portion of
        a generation plan) could be accomplished through the Day-Ahead
        Reconfiguration Service (DA-RCS).

        -   If transmission right holders[^15] give up their scheduling
            flexibility in the DA-RCS, there is a reduction in the
            \"headspace\"[^16] that must be set aside to meet
            obligations for pre-existing rights.

        -   Reduced \"headspace\" becomes AFC that can be sold as IWRs. 

        -   A voluntary day-ahead redispatch is a partial energy market
            that must be settled against a real-time energy market, but
            since not all parties participate, the optimization achieved
            can be undone by parties who retain their pre-existing
            scheduling flexibility. In addition, without a real-time
            energy market applicable to all users, settlement of
            commitments was problematic. Finally, it appeared that there
            were potential gaming problems that would have to be
            addressed.

    v.  Enhancing the DA-RCS to handle releases of scheduling
        flexibility avoids the complications of the day-ahead redispatch
        service while achieving its objectives, namely making more
        capacity available through voluntary offers to restrict changes
        in generation patterns for the following day.

    vi. With this modification, the typical day for pre-scheduling fits
        the general pattern in place today.

        -   Trades for the next day occur very early in the morning.

        -   Calls are made to find transmission from various
            transmission providers.

        -   Pre-schedules are submitted.

    vii. The enhanced DA-RCS allows individual providers to find
         transmission through a central auction conducted by Grid West,
         where AFC is made available by releases of scheduling
         flexibility along with AFC and other transmission rights sale
         offers.

c.  [Rights Translation]{.underline}.

    i.  For many years, pre-existing transmission rights are expected to
        represent the majority capacity commitments of the Grid West
        Managed Transmission System. Therefore in order to have a
        successful Reconfiguration Service, pre-existing right holders
        must have a way to offer their rights for sale in the RCS
        auction. This is enabled through a rights translation process.

    ii. If a right holder wishes to offer rights in the RCS, it will
        come to Grid West and request a translation of its rights into
        an equivalent set of IWRs. This translation may be partial,
        i.e., some IWRs and a residual retained right, with the combined
        set having no greater capacity commitments than were required
        for the original rights.

    iii. Once a translation is "certified", the right holder may (1)
         choose to do nothing and use its rights as before, or (2)
         release some or all of the identified IWRs into an RCS auction
         for a specific period (for instance, for all hours of the next
         day) and if sold, schedule its own use based on the residual
         retained right.

    iv. A decision to offer rights in one auction does not bind the
        right holder to offer in any future auction. For instance, if a
        right holder offers IWRs for all hours of the next day in
        today's DA-RCS, it could subsequently choose not to release any
        IWRs in tomorrow's DA-RCS and schedule using its original
        transmission rights.

    v.  Scheduling flexibility for pre-existing rights can also be
        translated and released into the DA-RCS.

d.  [Treatment of Pre-Existing Firm Redirect Services]{.underline}.

    i.  Under today's open access transmission tariffs, transmission
        customers may request that their Points of Delivery (PODs) and
        Points of Receipt (PORs) be changed or redirected to other PODs
        and PORs on either a temporary or permanent basis. Redirects are
        granted only if transmission capacity is available to enable the
        request. In the case of a permanent redirect, the new points are
        firm. Most transmission providers offer temporary redirects on a
        non-firm basis only.

    ii. When Grid West becomes the manager of available capacity for the
        Grid West Managed Transmission System, only Grid West will be
        able to make such availability determinations.

    iii. After Grid West is operational, Transmission Owners who receive
         redirect requests under pre-existing contracts will only be
         able to grant requests after Grid West has confirmed
         availability.

e.  The white papers dealing with transmission right trading are:

    i.  ***[Reconfiguration White Paper]{.underline}*** -- Describes the
        implementation of the reconfiguration service: mechanisms for
        determining pre-existing obligations, auction rules and pricing
        of IWRs sold and purchased.

        -   A series of auctions addresses different time periods:

            -   Annual for monthly on-peak and off-peak IWRs.

            -   Monthly for monthly on-peak and off-peak IWRs for the
                balance of the annual period of the auction cycles.

            -   Intra-monthly for daily on-peak and off-peak IWRs for
                the balance of a month.

            -   Day-Ahead for hourly IWRs for the next day.

        -   The Day-Ahead Reconfiguration Service (DA-RCS) will have an
            enhanced feature to enable trading of scheduling
            flexibility.

    ii. ***[Redispatch White Paper]{.underline}*** -- Describes the
        day-ahead redispatch service envisioned in the original Regional
        Proposal and explains how the objectives of day-ahead redispatch
        will be met by enhancements to the Day-Ahead Reconfiguration
        Service without encountering the difficulties of reconciling
        day-ahead bids with real-time imbalances that were discovered
        during TSLG's Layer 1 work.

    iii. ***[Bilateral Trading White Paper]{.underline}*** -- Evaluates
         the effects of Grid West proposed services and functions on
         current bilateral trading practices within the Grid West
         footprint.

    iv. ***[Rights Translation White Paper]{.underline}*** -- Describes
        the processes and functions used by Grid West to manage
        transmission rights data. This includes methods for identifying
        the injection and withdrawal commitments associated with
        pre-existing agreements and obligations and for allow
        pre-existing right holders to translate their rights into IWRs,
        either in whole or in part, for release in reconfiguration
        auctions.

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6.  ***[Scheduling Related Processes]{.underline}***

    a.  Grid West will provide scheduling services for the use of the
        Grid West Managed Transmission System.

        i.  Initially the Transmission Owners will determine compliance
            with pre-existing contracts and adjust their own use to keep
            commitments within the limits of the owner's system.

        ii. A transition of functions to Grid West will occur over a two
            year period.

    b.  The white papers on scheduling related processes are:

        i.  ***[Market Information Services White Paper]{.underline}***
            -- Explains data and functional features of the OASIS used
            by Grid West for service requests, reconfiguration,
            scheduling and operational activities.

        ii. ***[Outage Coordination White Paper]{.underline}*** --
            Describes the proposed Grid West process for coordinating
            outages with regional scheduling and consolidated control
            area operations.

        iii. ***[Scheduling White Paper]{.underline}*** -- Describes
             process and data needed by Grid West and its participants
             to schedule transactions including tagging requirements,
             timing requirements, etc. The paper describes the proposed
             process for adjusting schedules, after the completion of
             the day-ahead process but before the cut-off to real-time
             operations, acceptance or rejection of adjustments based on
             assuring reliable operation in real-time, and the checkout
             procedures required to ensure accurate interchange and Net
             Scheduled Interchange with neighboring interchange
             authorities.

        iv. ***[Losses White Paper]{.underline}*** -- Describes the
            treatment of losses for pre-existing agreements and options
            for loss recovery/accounting methods that could be used for
            IWRs issued by Grid West.

7.  ***[Real-time Operation]{.underline}***

    a.  At the close of the scheduling adjustment period and just prior
        to real-time operations, schedules will be handed-off to Control
        Areas for implementation.

    b.  The general white papers dealing with real-time operations are:

        i.  ***[NERC Functional Model White Paper]{.underline}*** --
            Describes proposed roles and responsibilities for Grid West
            and participants to meet the requirements of the NERC
            functional model.

        ii. *[**Real**-**time Monitoring White Paper**]{.underline}* --
            Describes the proposed real-time monitoring process
            including the data needed to support both reliability and
            market functions.

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4.  **Control Area Consolidation**

    1.  ***[Voluntary Control Area Consolidation]{.underline}***

        a.  The Regional Proposal[^17] noted that some of the
            Transmission Owners expected to be within the Grid West
            footprint were discussing the possibility of consolidating
            their individual control areas. Grid West would provide the
            services needed by the consolidating parties to operate the
            Consolidated Control Area (CCA). The motivations of those
            considering participating in the CCA include increased
            reliability and operational efficiencies.

            i.  *[Reliability]{.underline}* -- Consolidation of control
                areas, by those Grid West Transmission Owners expected
                to voluntarily participate, will put certain control
                functions for a substantial portion of the regional grid
                under a single operator who will have authority to take
                appropriate actions when needed. The need for wider
                visibility outside of individual control areas was
                identified as means of improving the capability of
                operators to make proactive adjustments to protect
                system reliability.[^18] Consolidation of control areas
                with an associated investment in infrastructure will be
                necessary to obtain this benefit.

*[Operational Efficiencies]{.underline} --* Consolidation is expected to
reduce the total requirement for regulating reserves and balancing, due
to diversity among the loads and generation within the CCA. Furthermore,
the establishment of a market for providing the Interconnected
Operations Services (IOS)[^19] necessary for operating the CCA is
expected to reduce the cost of ancillary services.

*[Transmission Utilization]{.underline}* -- The CCA will be able to make
full use of transmission capacity within its boundaries in real time to
follow load, respond to contingencies, etc. without regard to facility
ownership.

*[Voluntary Participation]{.underline}* -- In keeping with the voluntary
nature of control area consolidation, each existing control area
operator will make its decision about whether or not to join the CCA
based on it is own assessment of the benefits to be obtained.

2.  ***[Grid West as a Control Area Operator]{.underline}***

    a.  Grid West will operate a Consolidated Control Area (CCA) for
        those who voluntarily choose to consolidate to obtain the
        benefits described in Section 4.1.

        i.  The IOS needed by Grid West for CCA operation are:

            -   Capacity arranged day-ahead to obtain contingency
                reserve and regulating reserve needed for system
                operations.

            -   Energy options (i.e., incremental and decremental
                offers) for balancing load, generation and interchange
                in real-time.

        ii. Grid West will obtain IOS by operating markets since it is
            neither an owner of, nor in control of, any of the assets
            needed to provide these services. These markets will provide
            price transparency, which will benefit both buyers and
            sellers and assist in market monitoring efforts.

            -   A Reserves Market will be used to obtain capacity
                related IOS.

            -   A Balancing Service that will be a market using
                voluntarily offered real-time energy options for
                balancing system requirements.

Grid West will encourage all market participants to make offers to
provide these IOS to the CCA. Their participation will provide a wider
range of options with lower costs and greater efficiency.

Service costs for CCA operation will be separated from other Grid West
activities that apply to the entire Grid West Managed Transmission
System.

b.  The white papers dealing with real-time operations within the CCA
    are:

    i.  ***[Real-time Balancing Service White Paper]{.underline}*** --
        Describes the operation of the balancing service used to obtain
        balancing energy, while considering the nature and types of
        energy offers, selection of resources, the command and control
        process for dispatch of resources selected to provide balancing,
        dispatch granularity, dispatch frequency, control signals
        process and routing, load following, AGC, etc.

    ii. ***[Emergency Operations White Paper]{.underline}*** --
        Describes the proposed emergency operations process covering
        topics that include contingency events, emergency levels, etc.

c.  The white papers dealing with reserves are:

    i.  ***[Reserve Market White Paper]{.underline}*** -- Describes the
        proposed operation of the reserve auction, including reserve
        requirements, limited offer obligations of consolidating
        parties, inputs and outputs to reserve markets, locational
        nature of requirements and offers, etc.

    ii. ***[Deployment of Reserves White Paper]{.underline}*** --
        Describes the procedures to be used to deploy the reserves in
        real time that were obtained through the Reserve Market.

    iii. ***[Reserve Sharing White Paper]{.underline}*** -- Describes
         the current Northwest Power Pool reserve sharing agreement and
         the role of Grid West as a control area operator in future
         reserve sharing.

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5.  **The Rest of the Story**

    1.  ***[Administrative Functions]{.underline}***

        a.  In order for Grid West to provide the services described
            above, a number of administrative functions must be put in
            place. While these functions may appear to be pedestrian in
            their nature, they are critical to the success of Grid West.
            Failure to manage credit, to render bills accurately, to
            collect fees expeditiously and to resolve disputes quickly
            can debilitate Grid West's ability to function.

        b.  The white papers dealing with administrative functions are:

            i.  *[**Meter Data Management**]{.underline}* -- Describes
                the proposed meter data management process, including
                SCADA vs. revenue quality metering, load accounting,
                calibration, etc.

            ii. ***[Settlement and Billing]{.underline}*** -- Describes
                the proposed process for settlement and billing for Grid
                West services and markets, including settlements
                frequency, types of settlements, types of charges, roles
                and responsibilities for tariff billings, credit
                management, etc.

            iii. *[**Invoicing & Payment Processing**]{.underline}* --
                 Describes the proposed process for invoicing and
                 payments, including invoice frequency, late payments,
                 counter-parties, short-pay scenarios, etc.

            iv. ***[Dispute Processing and Alternative
                Resolution]{.underline}*** -- Describes the use of the
                Grid West ADR process for resolving settlement and
                billing disputes, including the resolution timelines,
                resettlement thresholds, etc.

    2.  ***[Reference Papers]{.underline}***

        a.  While developing the white papers described above, a number
            of general topics were covered by TSLG that apply to more
            than one of the white papers. The reference papers described
            below provide information which is supplemental to the white
            papers.

        b.  The reference papers are:

            i.  ***[Transmission Modeling Reference
                Paper]{.underline}*** -- Describes the methodologies to
                be used by Grid West for study and analysis of Grid West
                Managed Transmission System for regional planning,
                capacity expansion, reconfiguration service, scheduling,
                dispatch and real-time monitoring.

            ii. ***[Auction Pricing Reference Paper]{.underline}*** --
                Describes the pros and cons of two auction pricing
                methods -- market clearing price and as-offered-price --
                and the rationale for selection of the market clearing
                price for use in Grid West markets.

            iii. ***[Congestion Management Reference
                 Paper]{.underline}*** -- Describes the Grid West
                 approach to congestion management, which differs from
                 that used in other RTOs. By using a flow-based method
                 for issuance of new physical transmission rights, Grid
                 West addresses congestion before it occurs through
                 planning, capacity expansion and reconfiguration. Other
                 tools include scheduling, schedule adjustment and
                 curtailments, and the operation of the reserves market,
                 the real-time balancing services and real-time
                 operations.

            iv. ***[Registration and Commercial Model Reference
                Paper]{.underline}** --* Describes the proposed process
                for registering and modeling the assets of market
                participants including defining locations, load
                accounting, scheduling coordinators (or agents) and
                describes the use of load zones and trading hubs in
                scheduling and in acquisition of IWRs.

            v.  ***[Seams Coordination White Paper]{.underline}*** --
                Describes the seams issues that will impact Grid West
                operations, including timeline coordination, intertie
                scheduling curtailments, loop flow management, etc.

> ***Appendix A***
>
> ***List of TSLG Papers***
>
> ***For Layer 2 Design***
>
> ![](media/image1.wmf){width="6.489583333333333in"
> height="4.854166666666667in"}
>
> [Figure A.]{.underline}
>
> Chart of white papers and reference papers that
>
> describe the conceptual framework for market and operational
>
> design for Grid West Basic Features (paper numbers keyed to list
> below).

**[The White Papers]{.underline}**:

1.  ***[Regional Planning & Capacity Expansion White
    Paper]{.underline}*** -- Describes the regional planning process to
    be facilitated by Grid West and the mechanisms for capacity
    expansion. Grid West will develop an open transmission planning
    process that examines expansion needs from a single system
    perspective, tests for transmission adequacy and considers
    non-transmission alternatives to meeting system needs. The capacity
    expansion service will deal with requests for long-term service
    requests (greater than one year). If capacity is not available to
    meet the request, the capacity expansion service enable market
    driven transmission projects to meet requests. It also provides for
    expansion backstops for maintaining existing transfer capability and
    meeting transmission adequacy standards.

2.  ***[Tariff Administration White Paper]{.underline}*** -- Describes
    the provision of transmission service through the Grid West Tariff
    and the related Transmission Owner Tariffs. It describes the roles
    of Grid West, the Transmission Owners and the transmission
    customers, and it provides discussion of issues related to
    pre-existing contracts, such as load growth, contract termination or
    roll-over, etc.

3.  ***[Reconfiguration White Paper]{.underline}*** -- Describes the
    implementation of the reconfiguration service: mechanisms for
    determining pre-existing obligations, auction rules and pricing of
    IWRs sold and purchased.

    a.  A series of auctions addresses different time periods:

        -   Annual for monthly on-peak and off-peak IWRs.

        -   Monthly for monthly on-peak and off-peak IWRs for the
            balance of the annual period of the auction cycles.

        -   Intra-monthly for daily on-peak and off-peak IWRs for the
            balance of a month.

        -   Day-Ahead for hourly IWRs for the next day.

    b.  The Day-Ahead Reconfiguration Service (DA-RCS) will have an
        enhanced feature to enable trading of scheduling flexibility.

4.  ***[Redispatch White Paper]{.underline}*** -- Describes the
    day-ahead redispatch service envisioned in the original Regional
    Proposal and explains how the objectives of day-ahead redispatch
    will be met by enhancements to the Day-Ahead Reconfiguration Service
    without encountering the difficulties of reconciling day-ahead bids
    with real-time imbalances that were discovered during TSLG's Layer 1
    work.

5.  ***[Bilateral Trading White Paper]{.underline}*** -- Evaluates the
    effects of Grid West proposed services sand functions on current
    bilateral trading practices within the Grid West footprint.

6.  ***[Rights Translation White Paper]{.underline}*** -- Describes the
    processes and functions used by Grid West to manage transmission
    rights data. This includes methods for identifying the injection and
    withdrawal commitments associated with pre-existing agreements and
    obligations and for allow pre-existing right holders to translate
    their rights into IWRs, either in whole or in part for release in
    reconfiguration auctions.

7.  ***[Market Information Services White Paper]{.underline}*** --
    Explains data and functional features of the OASIS used by Grid West
    for service requests, reconfiguration, scheduling and operational
    activities.

8.  ***[Outage Coordination White Paper]{.underline}*** -- Describes the
    proposed Grid West process for coordinating outages with regional
    scheduling and consolidated control area operations.

9.  ***[Scheduling White Paper]{.underline}*** -- Describes process and
    data needed by Grid West and its participants to schedule
    transactions including tagging requirements, timing requirements,
    etc. The paper describes the proposed process for adjusting
    schedules, after the completion of the day-ahead process but before
    the cut-off to real-time operations, acceptance or rejection of
    adjustments based on assuring reliable operation in real-time, and
    the checkout procedures required to ensure accurate interchange and
    Net Scheduled Interchange with neighboring interchange authorities.

10. ***[Losses White Paper]{.underline}*** -- Describes the treatment of
    losses for pre-existing agreements and options for loss
    recovery/accounting methods that could be used for IWRs issued by
    Grid West.

11. ***[NERC Functional Model White Paper]{.underline}*** -- Describes
    proposed roles and responsibilities for Grid West and participants
    to meet the requirements of the NERC functional model.

12. ***[Real-time Monitoring White Paper]{.underline}*** -- Describes
    the proposed real-time monitoring process including the data needed
    to support both reliability and market functions.

13. ***[Real-time Balancing Service White Paper]{.underline}*** --
    Describes the operation of the balancing service used to obtain
    balancing energy, while considering the nature and types of energy
    offers, selection of resources, the command and control process for
    dispatch of resources selected to provide balancing, dispatch
    granularity, dispatch frequency, control signals process and
    routing, load following, AGC, etc.

14. ***[Emergency Operations White Paper]{.underline}*** -- Describes
    the proposed emergency operations process covering topics that
    include contingency events, emergency levels, etc.

15. ***[Reserve Market White Paper]{.underline}*** -- Describes the
    proposed operation of the reserve auction, including reserve
    requirements, limited offer obligations of consolidating parties,
    inputs and outputs to reserve markets, locational nature of
    requirements and offers, etc.

16. ***[Deployment of Reserves White Paper]{.underline}*** -- Describes
    the procedures to be used to deploy the reserves in real time that
    were obtained through the Reserve Market.

17. ***[Reserve Sharing White Paper]{.underline}*** -- Describes the
    current Northwest Power Pool reserve sharing agreement and the role
    of Grid West as a control area operator in future reserve sharing.

18. *[**Meter Data Management**]{.underline}* -- Describes the proposed
    meter data management process, including SCADA vs. revenue quality
    metering, load accounting, calibration, etc.

19. ***[Settlement and Billing]{.underline}*** -- Describes the proposed
    process for settlement and billing for Grid West services and
    markets, including settlements frequency, types of settlements,
    types of charges, roles and responsibilities for tariff billings,
    credit management, etc.

20. *[**Invoicing & Payment Processing**]{.underline}* -- Describes the
    proposed process for invoicing and payments, including invoice
    frequency, late payments, counter-parties, short-pay scenarios, etc.

21. ***[Dispute Processing and Alternative Resolution]{.underline}*** --
    Describes the use of the Grid West ADR process for resolving
    settlement and billing disputes, including the resolution timelines,
    resettlement thresholds, etc.

**[The Reference Papers]{.underline}**:

22. ***[Transmission Modeling Reference Paper]{.underline}*** --
    Describes the methodologies to be used by Grid West for study and
    analysis of Grid West Managed Transmission System for regional
    planning, capacity expansion, reconfiguration service, scheduling,
    dispatch and real-time monitoring.

23. ***[Auction Pricing Reference Paper]{.underline}*** -- Describes the
    pros and cons of two auction pricing methods -- market clearing
    price and as-offered-price -- and the rationale for selection of the
    market clearing price for use in Grid West markets.

24. ***[Congestion Management Reference Paper]{.underline}*** --
    Describes the Grid West approach to congestion management, which
    differs from that used in other RTOs. By using a flow-based method
    for issuance of new physical transmission rights, Grid West
    addresses congestion before it occurs through planning, capacity
    expansion and reconfiguration. Other tools include scheduling,
    schedule adjustment and curtailments, and the operation of the
    reserves market, the real-time balancing services and real-time
    operations.

25. ***[Registration and Commercial Model Reference Paper]{.underline}**
    --* Describes the proposed process for registering and modeling the
    assets of market participants including defining locations, load
    accounting, scheduling coordinators (or agents) and describes the
    use of load zones and trading hubs in scheduling and in acquisition
    of IWRs.

26. ***[Seams Coordination White Paper]{.underline}*** -- Describes the
    seams issues that will impact Grid West operations, including
    timeline coordination, intertie scheduling curtailments, loop flow
    management, etc.

[^1]: Thomas P. Hughes, [Networks of Power, Electrification in Western
    Society, 1880-1930]{.underline}, Johns Hopkins University Press,
    Baltimore, MD 21218, 1983, pp. 282-283.

[^2]: "Regional Representatives Group, Regional Transmission Problems
    and Opportunities List, Organized by General Categories - Update and
    Accompanying Notes," August 14, 2003,

    <http://gridwest.org/Doc/RRGA_RefinedListClean_Aug142003.pdf>.

[^3]: Impedance is a measure of the opposition of an electrical element
    to a change in power flow in an AC network. It includes the effects
    of both the resistance and inductance of an electrical element
    (line, transformer, etc.), where inductance is a measure of the
    magnetic field effects created by current flowing in an electrical
    element.

[^4]: Loop flow or unscheduled flow is also called parallel flow within
    the industry. All three terms are equivalent.

[^5]: In spite of the difficulties of loop flow, no system has ever
    proposed cutting its interconnections to other systems in the West.
    This is unspoken testimony to the great value of interconnected
    transmission systems for both economic savings and system
    reliability.

[^6]: A nomogram is a graphic representation of the interdependence
    among transmission paths. These graphs show the tradeoff that must
    be made in reaching a simultaneous maximum flow. As flow is
    increased on one path it must be reduced on a parallel path.

[^7]: Also called phase shifters or phase angle regulators, these
    devices installed in one of two parallel systems, can alter the
    apparent phase angle between their terminals and force (or draw)
    flow onto (or from) the parallel facilities.

[^8]: The region's first attempt at using flowgate rights in RTO West
    Phase 1 was too complex for practical implementation. The flowgate,
    physical rights model required each party to maintain a large,
    continually changing portfolio of rights on a set of critical flow
    gates. Limiting the number of critical flow gates to be considered
    was an approximation made to ease the user's burden. However by only
    considering a given set of identified constraints, adaptation was
    difficult as the system changed. If a new flowgate were deemed
    critical, each user's portfolios of rights would have to be restated
    each time a change occurred. However, the *coupe de grace* of this
    approach was the intractable problem of converting pre-existing
    rights to a distributed set of fractional rights. No unique set of
    such rights existed that would be agreeable to all parties.

[^9]: See Section 3.4a for more discussion on pre-existing transmission
    rights. Discussion of participation of pre-existing right holders in
    the Reconfiguration Services is provided in Section 3.5b and 3.5c.

[^10]: The term Available Transmission Capacity (ATC) has been used with
    the contract path model to designate an owner's uncommitted contract
    path capacity. In a flow-based method, the contract path no longer
    exists. Instead, service availability is determined according to the
    physical capacity of critical elements or flowgates. Flowgate may be
    a single line or transformer or a set of parallel facilities that
    can be treated as a single network constraint. The uncommitted
    physical capacity of a flowgate is called Available Flow Capacity
    (AFC). AFC is not based on ownership but on actual network effects
    of a transmission reservation. A given injection-withdrawal right
    will result in use of multiple flow gates, however, the Transmission
    Customer is not required to manage these details.

[^11]: See the Tariff Administration White paper for further discussion
    of pre-existing rights and obligations, rollover, load growth, etc.

[^12]: The rate design for collecting the R3A will be covered by the
    Pricing Work Group.

[^13]: The form of the Grid West Tariff and its relationship to
    Transmission Owner Tariffs has yet to be determined. Some propose
    that there be a standard set of new Transmission Owner Tariffs with
    Grid West acting as agent, while others propose a unified Grid West
    Tariff. At the completion of the Module 1 work, an owner option was
    suggested, but again the exact form of the tariff was not determined
    as of the date of this draft.

[^14]: "Narrative Description of RRG Platform Group Regional Proposal",
    December 24, 2003, pp. 7-8,
    <http://gridwest.org/Doc/FinalNarrative_RegionalProposal_Dec242003.pdf>.
    The Regional Proposal described an Independent Entity (IE) that has
    since been given the name Grid West.

[^15]: These flexible scheduling rights include those used for native
    load service by Transmission Owner and the largest potential source
    of releases of existing scheduling flexibility.

[^16]: Headspace is a term used to describe the capacity set aside prior
    to an RCS auction to preserve pre-existing rights, including the
    scheduling flexibility (or optionality) of transmission right
    holders to change their schedules after the close of the day-ahead
    scheduling process.

[^17]: "Narrative Description of RRG Platform Group Regional Proposal",
    December 24, 2003, pp. 11-12,
    <http://gridwest.org/Doc/FinalNarrative_RegionalProposal_Dec242003.pdf>.

[^18]: "A principal cause of the August 14 blackout was a lack of
    situational awareness, which was in turn

    the result of inadequate reliability tools and backup
    capabilities... Improved visibility of the status of the grid beyond
    an operator's own area of control would aid the operator in making
    adjustments in its operations to mitigate potential problems. The
    expanded view advocated above would also enable facilities to be
    more proactive in operations and contingency planning." [Final
    Report on the August 14, 2003 Blackout in the United States and
    Canada: Causes and Recommendations,]{.underline} U.S.-Canada Power
    System Outage Task Force, April 2004 pp. 159-160.

[^19]: IOS are generation services that, when combined with transmission
    services create ancillary services.