RTOS, Transmission and Tariff Design


Analyzing Multiple-Product Power Markets

Innovation Needed for Reliability and Market Success in the RTO Revolution

Rajat K. Deb, Lie-Long Hsue, Richard Albert and Pushkar Wagle*

LCG Consulting
4062 El Camino Real, Suite 112
Los Altos, California  94022


This Paper Appeared in Electricity Journal, March 2001


The reliability manager in the restructured electric power industry, which could be a for-profit transco, a non-profit ISO, or other Regional Transmission Organization (RTO) bears a number of responsibilities, spelled out in FERC Order 2000.  Meeting many of these responsibilities requires analysis through time of the interrelated growth of both loads and resources, including in particular merchant generation outside the direct control of the reliability manager.  Modeling tools that consistently represent events in multiple markets—including markets for electric energy, ancillary services, transmission, and generating capacity—can support the reliability manager. An example drawn from a forward-looking study of the Western Systems Coordinating Council shows how such tools can evaluate transmission and generation sufficiency following market-driven expansion of merchant generation, and offer a guide for the reliability manager’s grid-expansion planning process.

I. Introduction

Under FERC Order No. 2000, Regional Transmission Organizations (“RTOs”) are being created to operate regional transmission systems and satisfy eight minimum functions, including the provision of ancillary services.  The RTO manager must offer open access while satisfying operational and market constraints.   Numerous buyers and sellers making multiple transactions complicate the problem of determining levels of transmission adequacy and identifying the likelihood of conditions leading to transmission system congestion.  This article discusses the RTO functions and how appropriate modeling tools can contribute to their performance.  The article is organized as follows.  First, the key policy problem—the development of transmission and wheeling tariffs under open-access utility unbundling—is reviewed.  Second, the functions of the RTO are reviewed, with attention to the analytic requirements of these functions.  Finally, an example modeling analysis is presented for the question of generation and transmission system adequacy for the Western Systems Coordinating Council (WSCC).

II. Regional Transmission Organizations

On December 20, 1999, the FERC issued Order No. 2000, which is intended to promote efficient, reliable, non-discriminatory transmission systems based on market mechanisms.  The order required that each public utility owning, operating or controlling electric transmission facilities file a proposal to participate in a Regional Transmission Organization (“RTO”) by October 15, 2000.[1]  Each RTO must demonstrate to the FERC that it will satisfy four specific characteristics and provide eight specific functions described in the Order.  Each RTO must also describe its transmission tariffs, justifying proposed innovative rate designs such as incentive and performance-based rates by cost-benefit analysis.

Since the filing deadline, several more-or-less complete RTO proposals have been filed with the FERC.  The PJM Interconnection (PJM), a non-profit ISO, argues in its filing that it is in fact an RTO.  Several new RTO’s have also filed, including the SPP RTO and RTO West.  The SPP RTO proposes to manage the transmission grid in its region, but leaves in place the existing structure of control areas and transmission ownership. RTO West, in contrast, will become the control area for its entire region (covering almost all of the transmission facilities in Washington, Oregon, Idaho, Nevada, and Montana); at the same time, six of the seven major investor-owned utilities (IOUs) in the region will transfer their transmission assets to an independent transmission company, TransConnect LLC.  Two RTOs based on a for-profit transco approach have filed proposals.  GridSouth Transco is proposed to administer the transmission assets of the IOUs in North and South Carolina; for the time being the IOUs will both retain ownership of  these assets and responsibility  for control-area operations.  The Southern Company, which owns utilities in Georgia, Alabama,  Florida and Mississippi, has proposed formation of SeTrans Grid Company, LLC, which would be a for-profit RTO which would assume control-area responsibilities in the region served by Southern’s utility subsidiaries, under the terms of a filed  open-access transmission tariff.

Several existing ISO’s, including the New England ISO (ISO-NE), the New York ISO (NYISO) and the California ISO (CAISO), have not yet filed, but may be expected to make similar arguments (although a recent FERC order proposing the replacement of the CAISO’s stakeholder governance with a board composed of unaffiliated individuals suggests some modifications to the CAISO filing).  In addition, there are a number of proposed RTO’s whose filings are expected in January, including a PJM West arrangement giving the PJM Interconnection control over the Alleghaney Power grid, the for-profit Alliance RTO and the Midwest ISO in the Midwest, and the Crescent Moon  and Desert STAR  RTOs in the Great Plains, Rocky Mountain  and Southwest states.

FERC Order No. 2000 specifies a number of functions that the RTO must perform, including:

  • Tariff design and administration;
  • Transmission congestion management;
  • Management of parallel-path/loop flow;
  • Procurement/provision of ancillary services necessary for grid operations;
  • OASIS administration, including identification of total transfer capability (TTC) and available transfer capability (ATC);
  • Market monitoring;
  • Transmission planning and expansion; and
  • Interregional coordination.

The current set of FERC filings by the new RTOs now being formed have focused on organizational structure, market rules, operating procedures and protocols, and legal and contractual mechanisms.  Appropriate modeling tools can contribute to the performance and refinement of many of these tasks.  Furthermore, future applications of modeling and price forecasting techniques in the new energy industry must take account of the particular features of the various RTO arrangements that govern wholesale power transactions in each region.   The Order might lead to the formation of as many as 20 RTOs.  Even a more modest number of RTOs will likely lead to common situations where individual power plants plan to sell to buyers located in more than one RTO and individual RTOs would obtain energy and ancillary services from out-of-region facilities.  Hence, inter-regional “seams” coordination will be important for efficient operations.

To satisfy FERC, as well as internal business strategy and due diligence requirements, transmission-owning utilities will find it essential to comprehensively evaluate their transmission/RTO business opportunities and risks.  Both qualitative and quantitative assessments will be needed in order to:

  • meet requirements for RTO filings under FERC Order No. 2000, including compliance with the 4 characteristics and 8 functions specified in the Order,
  • demonstrate the cost/benefit, reasonableness and equity of proposed rate designs, which must avoid “pancaking” while providing efficient market signals, adequate revenues and rates of return,
  • guide the refinement of structures and procedures that provide RTO operational and planning control while maintaining generation and transmission system adequacy and reliability,
  • develop a company’s overall business strategy appropriate for a changing future that includes deregulation and unbundling of market-based transmission services,
  • value a company’s transmission assets for purposes of developing a transmission business strategy or for transmission asset transferals such as divestiture, spin-off, or sale to a for-profit regional transmission entity, such as an electric Transco, i.e., an Independent Transmission Company.[2]

Transmission Pricing Practices for Wheeling Services

The transmission and distribution system in an electricity industry has two basic functions:

  • Providing the network infrastructure for electricity delivery
  • Assuring the reliability and security of the delivery process.

Thus, pricing of transmission and distribution services has two corresponding basic elements:

  • Charges for recovering the capital investment and operation and maintenance costs for the transmission and distribution network facilities and equipment.
  • Charges for assuring system reliability and security through so-called ancillary services and congestion management. 

When an electricity industry is organized as a vertically integrated regional monopoly, transmission and distribution service charges have generally been integrated with generation, general administration and other charges to form a single rate for customers within given classes, such as residential, commercial, and industrial.  This single rate for a specific customer class is usually developed by allocating a part of the total required revenues for the industry to this class and then dividing the allocated revenue requirement by the forecasted annual kWh to be sold to customers in this class. 

In an unbundled, restructured industry it is desirable to separate generation-related charges from transmission and distribution charges to avoid potential cross-subsidies.  After restructuring, generation charges can then be determined empirically by competitive market bidding or through bilateral contract negotiation.  However, it is often difficult to untangle the various cost components of the transmission and distribution system, because they are associated with the special physical characteristics of the electrical network as well as those of the power flows inside the network, which cannot be easily isolated. 

A widely used approach to reduce the complexity of the pricing mechanism is to separate the transmission and distribution system and their costs into various parts and then apply computational methods that strive for an empirical balance among economic efficiency, social equity, and computational practicality.  The choice of pricing mechanisms influences the cost of power (both the cost to generators and the cost of energy delivered to customers), investment signals to new generation and possibly to owners of transmission facilities, and the financial prospects for owners of existing generation and transmission assets.  The various outcomes of different pricing mechanisms may be modeled using simulation models that combine representations of both the behavior of market participants and the physical transmission grid.  This simulation modeling can contribute to decisions regarding the selection of transmission pricing mechanisms.

RTOs will evaluate the effects of differing pricing approaches for transmission services, while distribution services and their pricing will remain the responsibility of utility distribution companies (UDCs).  Because of the large amount of electricity involved and significant differences among customer services provided, it is usual to delineate the costs for transmission systems in greater detail than those for distribution system services.  Major categories of transmission service charges include:

  • System connection charges,
  • Wheeling, Access and Use charges, including

  • Capital investment charges,
  • Operation and maintenance charges, and
  • Congestion management charges
  • Ancillary service charges, including

  • Scheduling, system control and dispatch
  • Energy imbalance
  • Operating reserves
  • Spinning and supplemental reserves
  • Reactive supply and voltage control
  • Regulation and frequency response
  • Black start capability

Determining the computational basis for these charges is a delicate and complex exercise that has direct impact on the interests of owners and users of the transmission system.  The establishment of these charges is typically subject to regulation, almost always by the FERC since the transmission network involves generators and loads in several states (the main exception is the Texas grid, which is not synchronized to either the Eastern or Western Interconnect, and is regulated by the Public Utilities Commission of Texas.  The regulatory process involves balancing economic efficiency, social equity, the need to cover the financial and physical costs of the network, and administrative practicality.  Modeling for RTOs must show both the flow of payments associated with the various charges, and address the efficiency and equity issues of each.

System Connection Charges

Among these charges, system connection charges are probably the most straightforward and can often be determined by using an average charge for the connecting equipment and assigning a distance-related charge for the transmission line required to connect the new customers.

Wheeling, Access and Other Usage Fees

Charges related to use of the transmission grid itself involve wheeling charges assessed to transactions originating and/or terminating outside the RTO or ISO, other access charges assessed to all transactions using the transmission network, and fees assessed to users of constrained transmission facilities (known as congestion charges).

In the pre-ISO/RTO environment, the dominant methodology for managing transactions involving generators in one pricing region and customers in another is the so-called contract path approach.  This involves the assembly of transmission reservations on a sequence of connected transmission paths leading from the generator (source) to load customer (sink).  A typical contract path might cross the transmission systems of several transmission owners, each of which might require payment of a wheeling or access charge in order to schedule the transaction.  While this approach is administratively convenient, it corresponds poorly to the physical reality of the transmission grid.  In general, a balanced injection of power at one point and removal of power at another point changes flows on all paths of a network, not just on the contracted set of linking paths; the flows off the contract path are called loop flow, and are an unpriced use of network assets, which in addition complicates the real-time management of the interconnected grid.  In addition, as will be discussed below, usage fees unlinked to transmission constraints are inefficient, and the pancaking of such fees discourages efficient inter-regional trading of power.  These two sets of problems—loop flow and pancaking—are primary motivations for Order 2000, and modeling these issues is likely to be important to policy filings in response to the order.  In any event, contract-path approaches may continue to be used to price at least some power transactions, at least until a full system of RTOs is in place, with arrangements to avoid pancaking.

For capital investment and operation & maintenance charges, it is generally difficult to prescribe a precisely fair allocation of costs among either the customers or the generators beyond demand (MW) related and energy (kWh) related components.  Thus, for simplicity it is common to apply a postage-stamp approach to recover revenue requirements equally from all customers regardless of transmission distances.  An efficiency concern arises when the postage-stamp charge is not related to the opportunity costs of the transactions to which it applies.  Charging a fee for the use of transmission that is operating at below capacity discourages use of the transmission, and favors generation on the receiving or energy-deficit side of the transmission path, relative to generation on the sending or energy-surplus side of the path.  Congestion pricing, using either the difference in locational marginal prices between bus pairs (as is used, for example, in PJM), or the difference between prices in fixed zones (as in the California ISO), is more efficient.  However, the revenues from congestion pricing (including revenues derived from the sale of congestion-based financial instruments such as Firm, Fixed, and /or Financial Transmission Rights [FTRs]) may be insufficient to meet the financial and physical maintenance requirements of  many transmission assets; the non-congestion transmission-access and wheeling charges are a mechanism to finance these stranded assets.

The FERC has recognized that some inefficiency must be accepted to cover the stranded non-economic costs of the transmission network.  However, it identifies as a special concern the accumulation of the costs of this inefficiency associated with the pancaking of transmission access charges, which occurs when the postage-stamp charges of multiple jurisdictions are attached to a single transaction, typically a wheeling transaction between a power producer in one pricing region and a purchaser in another, with access charges applied in both regions (and possibly in other pricing regions involved in scheduling the transaction). 

An objective of the RTO initiative is to establish sufficiently large transmission regions in which pancaked access and wheeling charges will not be an issue.  Typically this involves a so-called “license plate” fee, assessed to one end of a transaction (typically the load side).  Such a mechanism is currently in use in two very different ISOs. 

The PJM region is an agglomeration of a large number of subregions, each served by a different utility, each of which has its own filed transmission access rates; transactions that end in PJM are charged one access fee, to cover the revenue requirements of the utility that serves the transaction’s sink, while transactions in which the sink is outside of PJM are charged a weighted average of the utility-specific fees.  The revenue requirements that are paid by the transmission access charge are, in turn, computed as each utility’s total filed revenue requirement, less the utility’s share of revenues from the auction of Fixed Transmission Rights, which captures the market value of the transmission grid in the presence of congestion. 

California is divided into three regions, corresponding to the service territories of the state’s three IOU’s.  As is the case in PJM, each of these utilities has its own filed revenue requirements, against which is credited the utility’s revenues from the sale of FTRs and from congestion.  When other transmission owners (TOs), such as municipal utilities and irrigation districts with ownership shares in transmission facilities, join the CAISO, their revenue requirements are combined with those of the existing TO(s) in the service-territory region, and a new Transmission Access Charge is computed to cover the joint net revenue requirement.  The access charge is applied to metered loads, based on their locations.  In effect this reproduces the mechanism used in PJM.  For wheeling transactions, the access charge that is applied is that in force for the pricing region in which the boundary scheduling point lies.

In both examples, the problem of pancaking is resolved for transactions that take place within the ISO (whether PJM or the CAISO).  However, there may be other access fees applied  “upstream” (on the source side) and/or “downstream” of the ISO on a wheeling transaction, thus producing a pancaking of additional charges unrelated to the economic (opportunity) cost of the transaction.  This is one of the “seams” issues alluded to by the FERC in its Order 2000.  One approach is to establish a cross-RTO reciprocity arrangement, a “license plate” on a larger scale.  Thus, RTO West proposes to negotiate reciprocal access-fee arrangements with its WSCC neighbors.  Such an arrangement could take the form of an elimination of the wheeling charge:  if all transmission access charges were based solely on the location of the final sink, then there would be no pancaking.  However, the owner(s) of transmission over which power is wheeled to serve a sink are, in this context, dependent on congestion revenues, access fees assessed on their own native loads, and/or a share of the access fees collected in the sink region.

The development of such reciprocity arrangements may well contribute to economic efficiency, by allowing the consistent use of low-cost out-of-region generation in preference to higher-cost within-region generation.  However, the arrangements will require negotiation (unless market-driven congestion revenues are sufficient to cover wheeling transmission facilities), which involves the evaluation of all sources of revenue to the owners of the involved transmission, which in turn requires estimation, or simulation, of the volumes of generation and loads across the full network, taking into account the physical limitations of the network.  Wheeling transactions (and consequent wheeling-fee revenues, which depend on the nature of any reciprocity mechanisms) as well as congestion revenues are computed based on the simulated dispatch; such information is critical to the evaluation of the impacts of a proposed access fee and access fee distribution mechanism.

Related sets of charges are those based on the distance.  These include MW-mile access charges and rules for accounting for network losses.

MW-mile charging for bilateral contracts, based on the distance between source and sink, have some appeal as they seem to tie charging for the grid to the physical grid resources used.  However, it has been argued that MW-mile charging for grid access amounts to nothing more than “smooth pancaking”, inefficiently discouraging use of below-capacity transmission facilities. 

Charges to account for transmission losses, on the other hand, can reflect an economic cost to distance.  A standard methodology for computing losses uses a load-flow model to estimate the change in total losses that results from a simultaneous 1MW increase in generation by the generator and a 1 MW increase in total loads.  Various approaches are used to assign or otherwise account for these losses.  In the California system, losses are computed ex-post, and a generator must buy balancing energy to make up for its losses (but it can avoid these charges by increasing its generation by a sufficient amount).  Alternatively, in a centrally controlled system (such as PJM), losses may be handled implicitly in the optimization process, with generation that contributes relatively heavily to losses receiving a lower locational marginal price (LMP) than does generation that tends to reduce losses.  Given accurate models of the physical grid, both approaches produce price signals to generation that accurately reflects the individual plant’s  transmission losses due to its location in the network.  Furthermore, the loss pricing produced by either model can be reproduced in a simulation model, so long as the simulation model also accurately represents the transmission grid.

To the extent that transmission rates (in particular wheeling and access charges) are not based on economic-cost principles (as are both congestion pricing and transmission-loss accounting), but instead are justified as cost-recovery arrangements (typically related to filed revenue requirements), rate designers (including in particular RTO managers) may adopt performance-based ratemaking principles, which are innovative regulatory schemes designed to accommodate cost-recovery requirements while delivering efficiency-enhancing incentives to the regulated utility.  An example of such an arrangement is a fixed stranded-asset charge, which is not subject to retroactive adjustment for additional profits from the market.  To set levels for such rates requires careful analysis of market behavior under the rates, and analysis which is equally necessary for utilities considering operation under the proposed arrangements.  Even where innovative rates are not included, due diligence would require the evaluation of prospective rates to ensure that RTO/ITC business strategies do not hinder opportunities for future innovative rates or products.

Some key challenges in evaluating performance-based rates in particular include:

  • defining appropriate performance benchmarks, perhaps based on congestion costs (several measures are possible) and market efficiency,
  • projecting and allocating among market participants the resulting savings or penalties for performing better or worse than benchmarks, and
  • projecting subsequent market responses, including bidding and prices (e.g., for energy, A/S, balancing energy, transmission rights), as well as future investment decisions.

As discussed above, the pricing system established by each RTO for use of the power grid will typically involve some combination of fixed grid-usage charges and congestion-management charges for the use of constrained paths.  These charges will have a direct impact on the prices that generators receive at different locations.  Thus, they can influence the pattern of energy dispatch and the locational incentives received by individual generators.  In a full multiple-market analysis, transmission charge rules and different tariff arrangements, short-run energy dispatch and costs, longer-term investments in generation, and transmission flows and revenues can be evaluated simultaneously to estimate effects on power flows, revenues and profits over time.

When congestion arises along a flow path, the costs of operating the system are likely to rise and operating limits are more likely to be exceeded.  Since one of the RTO’s primary functions is to ensure that physical dispatch remains consistent with loads and the physical capabilities of the grid, congestion management services have been developed to deal with load curtailment, system rebalancing, congestion payments and other related issues.

The costs of redispatch to relieve congestion and ensure more reliable grid operations can affect revenues earned by transmission owners and determine their incentives for maintenance and expansion of the transmission grid.  One way to deal with congestion is to create a market for Firm Transmission Rights (“FTR).  FTRs are supposed to encourage the efficient use of transmission assets through an economic market.  For example, when a constraint emerges on a particular flow path, the constraint would be measured via the market price for FTRs. The changing market price would provide an economic incentive for Scheduling Coordinators to adjust their schedules to free up some transmission capacity, in order to allow higher value transactions to take place.  Hence, the presence of FTR and recallable and non-firm transmission rights can provide economic incentives for market participants and permit the RTO to actively manage congestion.   Nevertheless, because market participants have differing incentives, devising workable FTRs is a process that many RTOs have yet to implement.

Congestion management charges are the most complex, because they depend on not only a more complicated protocol of power wheeling, but also on whether there is an open market for electric generation.  The development of these charges varies from simple postage-stamp cost allocation, such as in the UK, to a market-based price determination, as in California.

To identify and manage congested transmission lines or to implement FTRs, a model that integrates market behavior with Optimal AC Power Flow can be applied to project both the levels and costs of redispatch to relieve congestion through time, to compare the costs and benefits of additional transmission or generation projects that could relieve the congestion, and to estimate congestion revenues.  

Loop Flow

While power marketers typically engage in nominal point-to-point transactions by making the more-or-less implicit assumption of a single path between injection and take-out points, the RTO must model the full impact of transactions on the grid.  This typically involves every node combination in the network.  Even if the RTOs formal congestion management rules (such as pricing of congested transmission as if the grid were a small number of radially-connected hubs) are simplified for the convenience of grid users, the grid manager must respond to the physical properties of the full grid.  Thus, market modeling that incorporates a full grid model (such as an OPF) can identify flows across all nodal pairs and compare flows under alternate arrangements.

By eliminating pancaked tariffs and creating larger geographic areas under RTO control, the FERC hopes to reduce loop flows.  By projecting flows on designated transmission lines across particular interfaces, the effects of alternative tariff designs, differing geographic boundaries and expanded RTO membership can be assessed.

The provision of adequate contingency reserves (such as spinning and non-spinning ten-minute reserves), as well as the facilities for the maintenance of instantaneous balance between loads and resources, is a critical task of the RTO.  In Order No. 888, the FERC designated six Ancillary Services: 1) Scheduling, system control and dispatch service; 2) Reactive supply and voltage control from generation sources service; 3) Regulation and frequency response service;  4) Energy imbalance service;  5) Operating reserve – spinning reserve service; and 6) Operating reserve – supplemental reserve service.  Black start capability is sometimes considered an ancillary service, but it is procured separately from the others and is called upon infrequently compared to the other services.

Within these categories different “reliability products” may be provided.  These services are distinguished primarily by the responsiveness of the generators supplying the requested service.

Since these services require capacity, they add to the cost of delivering power.  Some arrangements may cause relatively low-cost generation to remain outside the energy dispatch, causing the dispatch of higher-cost generation.  Effective modeling of the electric energy market requires that the A/S procurement and charging rules be incorporated into the model.  In markets with RTO-managed dispatch of A/S, this requires modeling of the bidding behavior of participating generators and eliminating arbitrage opportunities among the multiple A/S markets.

Recovery of ancillary services charges are complex, because they involve not only the transmission system, but also the special characteristics of the generators and the loads they serve.  Determination of these charges generally starts with a set of pre-specified system standards for the services, such as the amount of each type of reserve required.  Setting charges for these services also depends on the specific protocols in each region.  In some regions, generators can self-provide ancillary services, so the costs will be internalized.  This is the case for the PJM Interconnection.  In other areas, the system operator will charge the generator based on a set of rules and postage-stamp type rates.  This is the case in Australia, the UK, and Japan.  In still other regions, the system operator will purchase services from the ancillary service market and charge market prices.  This is the case in California.

Open Access Same-time Information Systems (OASIS) is a fundamental service of RTOs and other providers of FERC-jurisdictional transmission systems.  These systems provide timely information about the total and available transfer capability of the transmission grid.  They are used by power marketers and others to develop transactions linking generation with loads.  In the process of modeling the transmission grid, an integrated power-market model requires monthly total transfer capability (TTC) information, and will calculate the hourly available transfer capability (ATC) as an output.

There are several approaches to the modeling of market power and other competitive aspects of power markets.[3] First, the traditional reliance on market-power indices (such as the well-known Hirschman-Herfindahl Index, or HHI) can be quantified for any dispatch situation, provided that the market model is capable of aggregation to owners/operators.  Second, a market model that simulates both prices and costs at specific locations can support the more direct measurement of the effects of market power through computation of markup-related indices such as the Lerner Index, or through simulations of welfare measures such as consumer or producer surplus.  In addition, the market and power flow effects of measures such as price caps or plant divestiture can be analyzed to help satisfy FERC’s required market monitoring function.  

Transmission planning is necessarily coordinated with generation expansion and load growth.  In a market-mediated transmission expansion analysis, simulation of energy deliveries over time allows estimation of congestion rents and the value of FTRs over time.  This quantification can, in combination with projections of grid access charges, produce projected revenue streams sufficient to justify and finance new transmission expansions.  In a more conventional transmission-planning context, an integrated generation/transmission market model can predict the location, frequency, timing and probability of future transmission insufficiency, thus contributing to the transmission planning exercise.  An example of this process for assessing reliability is discussed later in this section.

Interregional coordination involves the development of protocols across different control regions to allow the effective operation of the entire interconnected grid.  The effects of protocols between regions can be modeled just like the other elements of the transmission and dispatch tariff, including a variety of restrictions on interregional dispatch and reserve-provision practices.

Each of the FERC’s required RTO functions is likely to affect the others.  The UPLAN Network Power Model has been designed to provide the necessary integration, technical accuracy and flexibility to analyze these effects.  Table 1 illustrates how UPLAN addresses RTO functions:

FERC’s RTO Functions

UPLAN Treatment of Mandatory Functions

Tariff design & administration

Directly addressed via evaluation of alternative transmission tariffs and resulting contract flows, producing projected revenues and power transaction volumes. 

Transmission congestion management

Directly determined by optimal AC power flow analysis and UPLAN redispatch costs to relieve congestion. 

Parallel path flow (reduced loop flow)

Directly identified from calculated flows on specified paths and by simulation of measures affecting power flows. 

Ancillary services

Explicitly simulated by applying market design protocols: e.g., UPLAN treats CA, New England & PJM rules in its bidding and ISO dispatch functions for regulation/AGC, spin and non-spin reserves, replacement and real-time imbalance energy. 

Total Transmission Capability (TTC) and Available Transmission Capability (ATC)

TTC is input into the database for each line and interface and may vary by month. ATC is simulated hourly by the AC power flow calculation.

Market monitoring

Direct calculation of multiple measures of generator market power, as well as impact measures of bidding behavior, capacity withdrawal, and the effects of price caps. 

Transmission planning and expansion

Analyzed via alternative scenarios and built-in new entrant model for generation expansion, additions and retirements. Develops measures of transmission system adequacy.

Interregional coordination

UPLAN models each NERC region, as well as the Eastern, Midwestern and Southeastern Interconnected Systems, WSCC & ERCOT, plus flexibly defined RTO regions embedded within each regional grid.

Several examples of UPLAN applications to evaluate RTO reliability-related functions are described in the following sections.


III. The Reliability Problem:  Modeling Generation and Transmission System Adequacy

One of the RTO’s main roles is to maintain the backbone electric transmission grid, a set of tasks that involves coordinating, constructing, maintaining, and/or owning transmission facilities sufficient to support the efficient operation of the region’s generating facilities.  Traditionally reliability has been measured using a static index of Loss of Load Probability (LOLP), which takes into account only generation outages but assumes no uncertainties in demand.  LOLP is a long-term measure often used as a criterion for generation expansion.  However, in the deregulated market, merchant plant additions are based on economic criteria.  Hence, capacity additions cannot be dictated by solely by reliability measures, such as LOLP or reserve margin.

A number of indices may be calculated to measure reliability on a dynamic basis.  For example, the average unserved energy at each demand node measures the demand that would be interrupted due to shortages, transmission constraints or excessive loads. The standard deviation of the unserved energy gives a measure of the volatility of these occurrences.  Other measures include the frequency of load interruptions, as well as the variability and the standard deviation of load interruptions.   These numbers can be compared for cases with and before particular merchant plant additions, transmission reinforcements or transmission capacity additions. 

In the context of the traditional integrated utility, the transmission planning exercise is a straightforward but computationally complicated exercise involving the selection of transmission and generation expansion plans that minimize the total present-value cost of delivering uninterrupted power to the utility’s customers.  At every point on the grid in every hour (and in every reasonable contingency) there needs to be sufficient generating capacity to meet loads.  However, when the transmission grid is operated at capacity, there will be some incremental loads that can only be served by increasing the output of local generation.  In that circumstance an integrated planning process can compare the cost of delivering new generation to the cost of reinforcing the transmission grid to achieve an acceptable level of reliability.

Under a market-driven restructuring, the generation capacity decision and the transmission capacity decision are separate business decisions.  Yet, they remain inter-dependent.  The potential investor in additional generation capacity is interested in the future energy prices at a prospective location, which are likely to be influenced by the future state of the transmission grid.  In turn, the need for transmission and the profit opportunities for transmission reinforcements are determined in large part by future generation expansion.  In short, this is another multi-product example, where the two reliability-delivering products are generation capacity and transmission capacity.  Here again, the challenge is to make decisions that take account of concurrent decisions by other market participants.

Hence, reliability-capacity decisions are susceptible to analysis with multi-market simulation models.  In the following example we present such an analysis for the Western System Coordinating Council. This represents an actual simulation of how an ISO or a RTO may carry out planning function to maintain the transmission and generation adequacy requirement of the system. The base year of the study is 2003 and adequacy study is conducted for the future years 2004 and 2005.

UPLAN Analysis of Generation Adequacy

We analyzed generation and transmission adequacy planning using UPLAN  model for WSCC, with load growth projected over 10 year period from 2004 to 2013 , The model represents all the transmission line of 230 kV and up, approximately 800 thermal and hydroelectric generators and all the major transmission interfaces listed in the WSCC Path Rating Catalogue[4] For clarity, this presentation is limited major interfaces in California and zone effecting imports to and from California. And results are provided for the year 2005 only.. The modeling effort consists of simulation of the system before any generating unit addition in the future years, followed by an optimal expansion of generation and transmission for the future and finally, an adequacy analysis after the plant additions.

Table 2: Generation Expansion Plan for the Years 2004 and 2005 for the WSCC


Table 2 lists the new plant added to the system in 2003 and 2004 by UPLAN Optimal merchant Plant model for which the net present value of the plants is positive, given expected load growth, fuel prices and other fundamental economic variables.  The.  A variety of reliability analyses were performed, using Monte-Carlo techniques to simulate both market and physical events, such as local variations in loads, and forced outages of generation. One can compute, for example, the probability and expected duration of loss of load events, or the expected annual duration of transmission congestion. We undertake fifty simulations of the system both before and after the new plant addition.

A number of indices may be calculated to measure reliability on a dynamic basis.  For example, the average unserved energy at each demand node measures the demand that would be interrupted due to shortages, transmission constraints or excessive loads. The standard deviation of the unserved energy gives a measure of the volatility of these occurrences. Other measures include the frequency of load interruptions, as well as the variability and the standard deviation of load interruptions. These numbers can be compared for cases with and before and after the merchant plant additions, transmission reinforcements or transmission capacity additions. These occurrences are of vital interest to owners and planners of both generation and transmission assets. Table 3 describes the nodal unserved energy reports for 2005, for both cases, showing selected nodes in WSCC. These reports suggest that the projected unserved energy at all the nodes, on an average, is not only high before the new units are added to the system but also frequent as compared to the case after new unit addition. Duration curves of the average unserved energy in WSCC given in the figure 1 indicate that both the magnitude and the duration of the unserved energy are substantially higher before the plant additions.

Table 3. Unserved Energy Report for WSCC, 2005

Given the mean and variance of the distribution of average unserved energy at any node, we can calculate the additional economic capacity required in order to minimize the unserved energy at that node.[5] From Table 3 we can see that after all the units that are economically viable are added to the system there are 850 MWh (Standard deviation 575) unserved energy in Northern California. From the simulated cumulative distribution, (from the frequency and the magnitude of unserved energy)  we can see that an addition of approximately 127 MW of uneconomical (Reliability Must Run) capacity at the AIRPORT bus will reduce the unserved energy 40 MWh per year. The loss incurred in this investment should be borne by the RTO as a cost of reliability.

Table 4 shows an example of a transmission adequacy report, showing both duration and marginal and total annual costs and duration of congestion costs on selected transmission interfaces in California, given the expected generation and loads for 2005.  Figure 2 presents the chronological flows through COI (California-Oregon Interface), Path 15, PGE_SCE, and WOR (West of River) interfaces.  The flow duration curves are particularly helpful in analyzing the impact of an interface capacity on the number of hours the flow across the interface is constrained and the additional cost incurred for meeting the demand from higher cost generation. For example, consider flow duration in case of PGE_SCE. If the interface capacity for central to southern California is 1,000 MW, the interface will be congested for 2803 (32%) and 3679 (42%) hours before and after new capacity additions, respectively. Also in case of south to north Path 15 flow which is constrained we see no significant difference in the duration curves for both cases as all of the units added are in the expansion plan are outside California, and they do not have significant impact on the interface within California. 

Figure 2: Flow Duration Curves With and Without Generation Expansion for WSCC, 2005

For operational planning one can obtain the probability of congestion during a particular hour on the main interconnections, as well as the expected congestion prices on those paths and the expected congestion cost. The congestion costs shown here represent the differences between locational prices on either side of the congested interface in those hours in which use of the interface is constrained, minus relevant grid-access or wheeling charges.  It is, therefore, the marginal value of additional generation.  However, if additional transmission capacity is added the congestion will disappear and owners of the new lines have to recover their investment through appropriate transmission charges. It can be observed that the addition of the generating plants, as in case (a), adds into the congestion cost on the interfaces. For example, on an average the COI interface is congested during 183 hours in case of generation expansion, whereas in case of no expansion, the number of congested hours is restricted to approximately forty-nine. However, as shown in the Figure 3, the system-side congestion costs are lower at these interfaces in case of generation expansion than otherwise. It is important to distinguish between the level of congestion at the interface and the system-wide congestion due to congestion at that particular interface. We can infer that expanding generation capacity within California will not only reduce the level and the instances of unserved energy, but also reduce the level of average and total congestion cost in the WSCC region.

Table 4: Projected Transmission Adequacy: Summary of Congestion Cost at Selected Interfaces for the Year 2005 for the WSCC

Figure 3: Duration Curves of the Projected Congestion Cost With and Without Generation Expansion for WSCC, 2005

Mitigating Generation and Transmission Inadequacy

  The evaluations of future generation inadequacy, and of present and future transmission congestion, are components of the RTO’s critical mission of overseeing transmission grid development and operation to allow reliable and efficient grid operations.  At least three of the RTO functions identified in FERC Order 2000 (and reviewed in Table 1) are directly involved.  First, the RTO’s performance of its tariff design and administration function determines, in part, the ability of merchant generation to respond to growth in loads, in the context of the ongoing evolution of the physical transmission grid.  Second, impending shortages of generation, relative to load, produce episodes when market power may arise, which may (depending on the regulatory environment) produce dramatic price spikes, possible inefficiencies in grid operations and generation dispatch, and a visible role for the RTO’s market monitors. Third, the transmission planning and expansion function is very closely tied to analyses of future growth in loads and resources, while (depending on the tariff design) financing of grid expansions may be directly related to expected congestion and congestion revenues.

As the direct manager of the transmission grid, after primary responsibility for planning for grid expansion, the RTO must consider both the needs for grid expansions, and the impacts of financing such grid expansions on long-term growth of generating resources.  The congestion costs identified in tables 4 and figure 3 are a signal for grid expansion.  However, expansions that eliminate such rents would eliminate as well the market-based means of paying for such expansions.  Reinforcing the grid to the point where congestion is eliminated would require the imposition of usage fees on all generation and load, with no locational price signal.  However, it may be that some grid reinforcement may eliminate, at lower cost, the need for the installation of site-specific generation, allowing instead the construction of a few larger and more efficient plants.

Our generation adequacy analysis indicates that expanding generation capacity can reduce the level of unserved energy, particularly within California. The challenge for the reliability manager—ISO, RTO, or even state regulator—is as complex as the challenge facing the investor in new generation, or as that facing the manager, in complex and interrelated markets, of existing generation:  it is to evaluate the effectiveness of his decisions in achieving his goals, after taking into account the actions of competitors and of other participants in the new energy marketplace.  It is the problem of evaluating investment equilibrium over time.  Rational-expectations equilibrium pricing models, such as the UPLAN model, are effective tools to assist the resolution of these tools, to enable the efficient management of the power grid in a market-driven restructured industry.

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