Page 1 of 42 
Page 2 of 42 

RECENT ISO SOFTWARE ENHANCEMENTS 

AND FUTURE SOFTWARE AND MODELING PLANS

STAFF REPORT 

Prepared by the 

Federal Energy Regulatory Commission 

November 2011 

ACKNOWLEDGEMENTS 

Federal Energy Regulatory Commission Staff Team 

Richard P. O’Neill, Team Lead 

Thomas Dautel 

Eric Krall 

This paper was prepared by Commission Staff and based primarily on information provided by representatives of the various RTOs and ISOs, and 

reflects conditions as of the time such information was provided. The opinions and views expressed in this staff report do not necessarily represent 

those of the Federal Energy Regulatory Commission, its Chairman, or individual Commissioners, and are not binding on the Commission. This staff 

report contains analyses, presentations and conclusions that may be based on or derived from the data sources cited, but do not necessarily reflect the 

positions or recommendations of the data providers.
Page 3 of 42 

ISO Software Enhancements of The Last Decade and Future Software and Modeling Plans 

Introduction 

This paper provides a summary of the various market designs, and the components of each of these 

markets, utilized by the Regional Transmission Organizations (RTOs) and Independent System Operators 

(ISOs) subject to the jurisdiction of the Federal Energy Regulatory Commission (Commission), and provides an 

overview of the current practices and future plans of these RTOs/ISOs with respect to the software and 

modeling used to implement their markets, including the real-time and day-ahead markets for energy and 

ancillary services, as well as certain transmission and planning functions.1

In 1999, the Commission and Rutgers University sponsored a conference entitled The Next Generation 

of Electric Power Unit Commitment Models (1999 Conference).2

 At the time, Lagrangian relaxation (LR) and 

linear programming (LP) were the dominant algorithmic approaches used to solve day-ahead and real-time 

market problems. Because they are approximations to the physical market problem, these approaches generally 

yield suboptimal results. On the other hand, mixed integer programming (MIP) allows for better modeling of, 

and is theoretically capable of finding a better solution to, these problems. The modeling of the problem is 

limited by the robustness of the software, and, as a result, MIP had been abandoned earlier because it was 

generally found to be incapable of finding a good solution in the time required. One of the papers in the book 

presented computational advances and test results on unit-commitment problems, and, given its theoretical 

benefits, encouraged the RTOs/ISOs to test using MIP.3

Following the 1999 Conference, PJM tested MIP by solving the day-ahead market problem with both its 

existing software and MIP. Based on this test, the PJM Interconnection, LLC (PJM) found that the production 

(bid) cost savings on an annual basis were approximately $60 million. In 2004, PJM implemented MIP in its 

 1

 This paper was prepared by Commission Staff and based primarily on information provided by representatives 

of the various RTOs and ISOs, and reflects conditions as of the time such information was provided. The opinions and 

views expressed in this staff report do not necessarily represent those of the Federal Energy Regulatory Commission, its 

Chairman, or individual Commissioners, and are not binding on the Commission. This staff report contains analyses, 

presentations and conclusions that may be based on or derived from the data sources cited, but do not necessarily reflect 

the positions or recommendations of the data providers. 

2

 The 1999 Conference resulted in a book with the same title. See The Next Generation of Electric Power Unit 

Commitment Models, Hobbs, Rothkopf, O'Neill and Chao, eds. Boston, Dordrecht, London: Kluwer Academic Publishers, 

2001. 

3

 R. P. O'Neill, B. Hobbs, W. Stewart, R. Bixby, M. Rothkopf and H.P. Chao "Why This Book? New Capabilities and 

New Needs for Unit Commitment Modeling", The Next Generation of Electric Power Unit Commitment Models, Hobbs, 

Rothkopf, O'Neill and Chao, eds. Boston, Dordrecht, London: Kluwer Academic Publishers, 2001. 
Page 4 of 42 

day-ahead market. Subsequently, in 2006, PJM tested, and then implemented, MIP in its real-time market lookahead, with savings estimated at $100 million/year. 

On April 1, 2009, the California ISO (CAISO) implemented its Market Redesign and Technology 

Update (MRTU), which modified the pre-existing market design by establishing a nodal market model, 

locational marginal prices (LMP), a residual unit-commitment (RUC), and a day-ahead market. As part of 

MRTU, the CAISO also introduced MIP as the solution technique for the new market design. CAISO estimated 

savings from implementation of MIP in connection with MRTU to be $27 million/year. After April 2010, the 

CAISO further reduced the MIP gap tolerance4

 to achieve an additional $25 million/year annual estimated 

savings. Therefore, the ISO is currently achieving an estimated $52 million in annual estimated savings by 

using MIP. 

In 2009, Southwest Power Pool (SPP) also announced that it would add a day-ahead market to its 

existing market design, and would use MIP as the solution approach. SPP estimated that implementing the dayahead market and other enhancements would result in benefits of $103 million/year.5

 

This paper reports on the results of the 2010 surveys, including reported estimated cost savings, current 

plans for future implementation of MIP, and other market modeling and software improvements. 

 

4

 The gap tolerance is the difference between the best known feasible solution and a known bound on the optimal solution. 

5

 http://www.spp.org/publications/Economies_of_Scale_Market_Benefits.pdf 
Page 5 of 42 

Background 

Figure 1. ISO Map 

RTOs and ISOs cover a large portion of the U.S. (see Figure 1). Depending on the metric used, 

RTOs/ISOs serve between one-half and two-thirds of the U.S. electric power market. The remainder of the 

U.S. operates under bilateral open access transmission tariff (OATT) markets. The RTOs/ISOs have adopted a 

variety of market designs and services. For example, PJM, New York ISO (NYISO), ISO New England (ISONE), Midwest ISO (MISO), and CAISO all provide transmission service on the facilities owned by their 

members, and operate financial transmission rights, day-ahead, hour-ahead, and real-time markets for energy 

and ancillary services. Market settlement is based primarily on locational marginal pricing. SPP currently 

provides transmission service on the facilities owned by its members, and operates the region's real-time energy 

imbalance service (EIS) market. PJM, ISO-NE, and NYISO also operate capacity markets, and the MISO is 

developing a capacity market. CAISO and SPP, however, have no plans for a capacity market at this time. 

The configuration of the RTOs/ISOs has changed over time. On October 1, 2004, for example, PJM 

expanded west (see Figure 2) to include parts of Illinois, Ohio, West Virginia and Kentucky at a (one-time) 

expansion cost of approximately $40 million. Post-expansion, the annual gains from trade increased by about 
Page 6 of 42 

$180 million (over 20 years, about $1.5 billion in net present value efficiency gains), demonstrating the ability 

of better coordination through better software modeling to achieve efficiency gains.6

Figure 2. Pre and post expansion of PJM on Oct 1, 2004 

Market Survey 

 In September 2010, Commission staff issued a data request to the jurisdictional RTOs/ISOs requesting 

information on current practices and future plans for proposed software and/or modeling improvements to the 

real-time market, day-ahead market, and planning models. This document summarizes the results from that 

data request. 

Real-Time Market Look-Ahead 

The real-time market look-ahead is a tool that operates in the real-time, up to four hours prior to the 

real-time dispatch, which provides the market operator the ability to anticipate the need to start-up or shut-down 

generators with long lead times. Not all of the RTOs/ISOs currently utilize this tool. 

In a 2007 Commission staff survey, PJM stated that implementation of MIP in connection with its realtime market look-ahead tool and short term commitment models produced a time-coupled resource dispatch 

trajectory with estimated savings of $90 million to $130 million/year (including savings from its “Perfect 

Dispatch” program). 

 

6

 Erin T. Mansur and Matthew W. White, “Market Organization and Market Efficiency in Electricity Markets,” March 

March 31, 2009, Draft. http://www.industrystudies.pitt.edu/Chicago09/docs/Mansur%203.5.pdf 
Page 7 of 42 

Since 2009, CAISO has used MIP to improve the co-optimization of its energy and ancillary services, 

and to include a larger number of transmission constraints. 

MISO has an intra-day commitment process that looks out several hours before the real-time market. In 

the real-time market, MISO currently only dispatches already-committed units using an LP-based security 

constrained economic dispatch (SCED). MISO is currently implementing a real-time look-ahead commitment 

model using MIP with 15 minute intervals for up to a three hour period. 

NYISO currently has no real-time look-ahead market, but is planning to implement MIP in their market 

software.7

 The ISO-NE intra-day look-ahead is a reliability unit-commitment process to facilitate risk 

management and to pre-position generators for expected system changes. ISO-NE is investigating using MIP 

for its two-to-four hour look-ahead unit-commitment process. SPP also does not currently utilize a real-time 

look-ahead market. 

Residual Unit Commitment

The residual unit-commitment (RUC) is a process that strips out virtual bids, inserts the RTO’s/ISO’s 

forecasts of demand and variable energy resources, and commits any additional units needed for reliability. As 

of 2010, PJM, CAISO, ISO-NE, and MISO all were using MIP in their RUC processes. 

The NYISO currently uses LR in its RUC processwhich is integrated within the forecast pass 

optimization of the day-ahead market. NYISO is evaluating MIP as part of that process and expects MIP to 

provide incremental production cost benefits in the forecast pass of the day-ahead market. SPP plans to use MIP 

as part its RUC process in connection with its ongoing market re-design. 

. ISO-NE reports that uncertainties caused by wind power generation, load forecast, external 

transactions, and intermittent resources are being considered for future improvements. For example, ISO-NE 

reports that a robust optimization based approach is under investigation. 

MISO’s forward reliability assessment commitment (RAC) model is run soon after the close of the dayahead market and serves as its RUC process. The RAC minimizes the cost of committing the resources as 

measured by start-up, no-load, and the incremental energy costs of operating at minimum output. MISO also is 

investigating revised objective functions and other modeling changes. 

Day-Ahead Market

 

7

 Personal communication with Rana Mukerji, Vice President, Market Structures, NYISO. 
Page 8 of 42 

The day-ahead market is a 24-hour market that operates a day before real-time to commit, de-commit, 

and schedule generators with long start-up times, minimum run time and minimum down time. Until 2004, LR 

and LP were the dominant approaches to solving the day-ahead market. According to PJM, the implementation 

of MIP-based commitment in the PJM day-ahead market has reduced total production costs between $60 and 

$100 million annually and significantly reduced day-ahead market uplift. PJM reports that MIP is performing 

well and has no plans for additional algorithm upgrades at this time. 

Prior to the start of MRTU, the CAISO did not conduct a day-ahead market and relied on balanced 

schedules based on the bilateral forward market. Under MRTU, CAISO estimates operations are saving $23 

million/year. By 2010, ISO-NE, MISO and CAISO also had implemented MIP, and NYISO is targeting 

implementation of the MIP by 2013. In NYISO, the initial evaluation of MIP in the day-ahead market indicated 

an expected reduction in total system production cost and an improved selection of near marginal cost 

resources. 

Capacity Markets

Of the 3 RTOs/ISOs that have capacity markets, PJM and ISO-NE use MIP; NYISO uses LP. ISO-NE 

reports an estimated savings from MIP of $45 million. 

MISO is investigating a forward-looking capacity market with possible zonal requirements with simple 

import and export limits for the zones. 

Co-optimization of Energy and Ancillary Services

 Co-optimization is the simultaneous optimization of all products and services in the market over both 

time and space. Limitations of software currently prevent full co-optimization of all products and services in the 

RTO/ISO energy and ancillary services markets. As software improves, greater co-optimization is possible. 

NYISO, MISO, and CAISO co-optimize energy, contingency reserves, and regulation. In CAISO, realtime energy and ancillary services currently are co-optimized on a 15-minute interval basis in the real-time unitcommitment (RTUC) process. The ancillary service awards are binding in the RTUC, but the energy dispatch 

in the RTUC is not. CAISO is considering co-optimizing on a five-minute basis to make both ancillary services 

and energy binding on the same interval. 

ISO-NE and PJM co-optimize energy and reserves only. ISO-NE is conducting cost/benefit analysis of 

co-optimization of energy with regulation. PJM co-optimizes energy and reserves to make reserve/regulation 

assignments 30 minutes before the hour. The real-time five-minute dispatch will then incrementally modify 

reserve and regulation assignments, which is a limited form of co-optimization. However, PJM does not 
Page 9 of 42 

actually simultaneously optimize energy and reserves every five minutes. PJM currently plans to upgrade to a 

five-minute co-optimization of energy, contingency reserves, and regulation in 2011. 

SPP is planning to co-optimize energy, contingency reserves, and regulation service as part of its 

ongoing market re-design efforts. 

Ramp Rate Modeling

Ramp rate is the speed that a generator, or load, can change its output, or consumption, respectively. For 

generators, ramp rates vary depending on the power output. In the past, full ramp rate modeling was difficult 

due to non-convexities of ramp rates and subsequent computational difficulties. The fastest ramp ‘down’ is the 

dropping of load. 

CAISO allows multi-segment ramp rate bid curves for generators within integral multi-interval lookahead optimization in both day-ahead and real-time markets. ISO-NE has a single ramp rate in the real-time 

dispatch that is taken from one point of the multiple-ramp rate curve. The average ramp rate for the dispatch 

interval will be implemented in the real-time dispatch. 

MISO uses a single ramp rate in the day-ahead market and allows resources to submit a ramp rate curve, 

and different ramp up, ramp down, and bidirectional ramp rate limits in the real-time market.8

 MISO is 

considering allowing resources to submit different ramp up, ramp down, and bidirectional ramp rate limits in 

the day-ahead market. MISO is also considering including emergency ramp limits. 

NYISO uses a three-segment ramp rate for energy in both day-ahead and real-time. Multi-stage thermal 

units have indicated potential complications with both maintaining a constant ramp rate across their output 

ranges for regulation, and with regulating in ranges requiring supplementary (duct) burner firing. The NYISO is 

undertaking a project to evaluate the need and practicality of multi-segment ramp rates for ancillary service 

products. 

PJM uses up to 10 different ramp rates for different MW operating ranges. PJM is working to implement 

enhancements to allow ramp rates to differ depending on whether the unit is ramping up or down. 

SPP uses multiple ramp rates for dispatch purposes only. Futures plans include MW based ramp rate 

curve per generator for commitment, and multiple ramp rate curve types (ramp up, ramp down, and 

bidirectional ramp), for dispatch. 

Transmission Switching

 

8

 The bidirectional ramp rate limit is only for AGC capable units. 
Page 10 of 42 

Transmission switching (that is, taking out and inserting transmission elements into the transmission 

topology) is a widely used technique in power systems operations, but is not used in market optimization due to 

computational limitations. Specific instances of transmission switching are sometimes called “special protection 

schemes.” 

ISO-NE, NYISO, CAISO and PJM all use “special protection schemes” for transmission switching. 

NYISO, for example, captures transmission switching operations in the commitment and dispatch optimization 

processes to ensure the most efficient resource utilization is available prior to, during and after the outage. 

PJM, on the other hand, uses a semi-automated on-line powerflow analysis, with confirmation by engineering 

staff, when considering available switching options and/or bus reconfiguration to alleviate overloads, to avoid 

off-economic dispatch, and/or to avoid emergency load management. In 2011, PJM expects that a new energy 

management system will allow further automation of the process. 

MISO and SPP have not established any ‘‘special protection schemes.” CAISO is currently investigating 

using optimization to perform post-contingency corrective actions. 

Combined-Cycle Generator Modeling

Combined-cycle generators and some other generators can operate in several different configurations. 

Without MIP, the different configurations are difficult to model. With MIP, however, a much improved 

representation is possible. In PJM, there are several modeling approaches available to combined-cycle resource 

owners, and optimization can accommodate multiple/conditional offers in the PJM markets. In CAISO, the bid 

function is the same for all generators. In December 2010, CAISO implemented its new multi-stage generation 

modeling approach, which optimally selects the appropriate configuration to be used. Each configuration in a 

plant is modeled as a separate resource accounting for the time and cost dependencies between the different 

configurations. 

In MISO, each market participant must specify which combined-cycle plant configuration it is offering 

into the market. Only a single plant configuration may be offered for a combined-cycle generator. MISO is 

investigating enhanced modeling of the combined-cycle generators in which the unit-commitment model will 

select which configuration to use. In ISO-NE, resources are divided into approximate aggregate configurations. 

In SPP, each combined-cycle plant configuration is modeled as a unit and transition between configurations are 

modeled. 

The NYISO modeling utilizes a gas turbine/steam turbine coupled model(s) to represent the operating 

modes of the plant for commitment and dispatch of combined-cycle generation units. The model allows for the 

representation of individual gas turbine commitment costs to the optimization processes, and captures the 
Page 11 of 42 

combined unit operating characteristics for the dispatch tools. NYISO will be moving towards an MIP 

methodology by 2013. As part of the evaluation and implementation process, the NYISO is reviewing the 

potential for individual unit configuration for combined-cycle generators. 

Dispatchable Load Modeling

A significant element necessary for greater participation of demand response resources in the RTO/ISO 

markets is the need for enhanced market software computational capability. 

In the MISO, CAISO, PJM, and SPP markets, dispatchable loads are modeled on a basis similar to a 

generator with similar parameters. CAISO is currently considering further modeling enhancements for demand 

response. In ISO-NE, dispatchable loads do not currently have commitment parameters, such as minimum up 

and down time, but ISO-NE is considering introducing such commitment parameters into its market design. 

The NYISO approaches dispatchable load modeling in three methods. First, the day-ahead demand 

response program allows for the same full functionality as generator bidding to schedule economic demand 

reductions in the day-ahead market. Second, price cap functionality allows market participants to schedule their 

load purchases using predetermined limits. Third, NYISO allows dispatchable load the same full functionality 

as generator bidding to schedule economic demand reductions in the real-time market. 

In PJM, dispatchable loads can choose to be modeled nodally (i.e., as a single substation) and enter a 

complete set of offer parameters comparable with generators. Aggregated loads across multiple substations are 

also permitted, but the distribution of the load across the substations must be specified and all substations in the 

aggregate must be in the same transmission zone. PJM plans to upgrade load forecast and power flow 

optimization to accommodate widespread development of distributed price-responsive demand, and alternative 

technology such as storage and plug-in hybrid electric vehicles. Most of the effort is focused on upgrading 

system performance of the load model. 

Storage Modeling 

The RTOs/ISOs are evaluating the optimal use of storage and environmentally constrained resources. 

Certain RTOs/ISOs have already implemented measures to permit energy storage facilities to participate in both 

the real-time market and day-ahead markets. Some believe that storage facilities require more bidding options to 

allow greater market efficiency. 

The NYISO market offers the capability to economically schedule the production and recharge cycles of 

pumped storage facilities based upon the market clearing prices. The NYISO is targeting a project to evaluate a 
Page 12 of 42 

full co-optimization of physical and financial offers from storage devices, including recharge time, minimum 

cycle time and arbitrage spreads. 

In MISO, a pumped storage market participant can decide in which intervals the resource can be 

scheduled to generate, and in which intervals it can be scheduled to pump. In the intervals in which it can be 

scheduled to generate, the participant can submit an offer like any other generator. In intervals in which it can 

be scheduled to pump, the participant can submit a price sensitive demand bid. 

In ISO-NE, bids for pumping and generating from a pumped storage unit are optimized independently. 

The CAISO is considering further modeling enhancements for different types of storage. SPP’s new market 

design also will support pumped storage bidding. 

Modeling of Flexibility in Resource Limits 

Many constraints on power system assets are “soft,” meaning that such constraints are both a function of 

time and intensity of usage. Often, though, constraints that are actually “soft” are modeled as “hard,” or 

inviolate, in part due to a lack of understanding of the time and intensity function, and in part due to 

computational issues. For example, an excursion from a steady-state thermal constraint may be modeled as a 

“hard” violation even though this type of an excursion may, in fact, be more properly characterized as “soft.” 

The consequence of characterizing such an event as a violation may include the assessment of a high penalty 

price, which may create suboptimal market results. On the other hand, flexibility in resource limits can include 

relaxation of violation limits on flowgates, and in the determination of the economic minimum and/or economic 

maximum output of a resource. Additional examples of constraint modeling, and the consequences of such 

modeling, include the following. 

In CAISO, all resource-related limits are “hard” limits, except for daily energy use limits. Flowgate 

constraints are “soft” constraints. According to CAISO, it currently has no future plans to address these issues. 

Going forward, MISO provides that it plans to simply use the penalty price in trying to enforce 

transmission limits. Moreover, MW limits for resources such as generators depend upon operating conditions. 

For example, one set of limits may be used during normal operations, whereas Emergency Maximum limits 

may be employed during maximum demand situations, during which MISO is experiencing difficulty satisfying 

demand. Similarly, Emergency Minimum limits may be used when MISO experiences difficulty satisfying 

minimum operating limits. Such Emergency conditions allow operation beyond economic limits used in normal 

operations and are based on emergency offer segments of resources. The resource limits selected based on 

these operating conditions are enforced by setting high penalties on violations. 
Page 13 of 42 

In NYISO, demand curves for operating reserve, regulation, and transmission constraints that 

incorporate the assigned product shortage cost into the applicable market clearing prices were implemented in 

2005. Such shortage values need to reflect the value of reserves during shortage conditions, consistent with 

operational practice and reserve scheduling requirements. With appropriate shortage values, shortage pricing 

ensures appropriate pricing and scheduling results when the desired amount of reserves or regulation is 

unavailable. NYISO is re-assessing the operation of the current reserve and regulation shortage values and 

examining the continued applicability of the current set points. 

In PJM, the penalty adaptation has the objective of setting the resource’s limit at the upper bound of 

seasonal physical dispatch alternatives and is semi-automated (i.e., it is a function of distribution factors and 

resource offers relative to the unconstrained dispatch marginal price). “Economic” resource MW limits are 

dependent on operating conditions. On the other hand, “Emergency” limits allow resource operations beyond its 

economic limits based on emergency offer segments, which can include negative offers for minimum limits. 

PJM employs adaptive generation modeling, which modifies economic operating range dynamically based on 

unit dispatch trajectory and other parameters. 

With respect to transmission facilities, PJM adapts its transmission constraints based on dispatch 

conditions. Generally, lower voltage level facilities have higher penalty levels because there are fewer resource 

dispatch options. According to PJM it is working on an adaptive transmission constraint model, which will 

adapt penalties based on a comparison of the rate of change of flow to the limit of the transmission facility. 

In ISO-NE, the relaxation of transmission constraints includes high penalties. Adaptive transmission line 

rating is being considered for future implementation. 

In SPP, dispatching of resources includes penalty factors for violation of resource limits on flowgates, 

ramp rates, and balancing. The SPP market model includes a very high penalty parameter for relaxing resource 

limits. Penalties for different constraints will be determined during the implementation of the market design. A 

few on-going prototyping activities for transmission constraint pricing are under review, including adopting a 

MW dependent penalty price curve, sub-gradient base transmission pricing, and a convex-hull approach. 

AC Power Flow Models 

 AC power flow models describe the actual physics of the power system (at least to the extent that the 

power system parameter and configuration data are accurate), and include variables describing not only the real 

power (P) and voltage angles () considered in the DC power flow models, but also variables describing 
Page 14 of 42 

reactive power (Q) and voltage magnitudes (V). AC power flow models can be used in at least the following 

two ways. 

First, AC power flow models can be used to check the feasibility of a dispatch from a DC optimal power 

flow (DC OPF) model. In this process, the dispatch values for real power from the DC OPF are provided as 

inputs to an AC power flow model, which attempts to find a feasible solution given the restrictions on voltage 

and reactive power generation limits. Such a feasibility check does not attempt to further optimize the system 

on its own, although it is often used in an iterative, quasi-optimization process. In such a process, (1) a real 

power dispatch is obtained using a DC OPF, (2) that dispatch is fed into an AC power flow model that identifies 

constraint violations, (3) branch flow constraints (or other constraints) of the original problem are modified in 

an attempt to resolve the constraint violations observed in the AC power flow model, (4) the problem is resolved in the DC OPF with the updated constraints, and the process repeats starting at step (2). The process 

typically ends when a dispatch from the DC OPF is found that does not violate any constraints in the AC power 

flow model. 

 Second, AC power flow models can be used as the mathematical basis for a model optimizing real and 

reactive power dispatch, known as an AC optimal power flow (AC OPF) model. The AC OPF model includes 

voltage as a direct constraint, and can much more accurately express the branch thermal constraints. 

Historically, AC OPF models have not been used in power markets, in part because of limitations on software to 

handle the nonlinear functions contained in the AC power flow model. In addition, the application of AC OPF 

models in power markets have been limited based on a dispute over whether the relatively low cost of reactive 

power generation implies that reactive power can be ignored during system dispatch without significant effects 

on efficiency. 

 Examples of the manner in which DC OPF and AC OPF are utilized by the RTOs/ISOs includes the 

following. 

AC Power Flow Models in Real-Time Economic Dispatch 

 Currently, the ISO-NE employs a DC OPF with AC feasibility, and is reported to be conducting research 

on the risk-based security in SCED. PJM employs a DC-AC iteration and a decoupled AC model. The CAISO 

employs a decoupled AC model based on last 15-minute linearized loss and shift-factors. If a contingency or an 

event is declared, the AC model is based on the current state of the system. MISO employs a state estimator that 

incorporates an AC power flow model. The real-time market uses a linearization of the real power part of the 

power flow model with a correction of the limits for reactive flows. SPP employs a DC optimization interacted 

with AC real-time contingency analysis. 
Page 15 of 42 

 NYISO has indicated that it uses an approach other than a DC OPF, with AC feasibility check, DC-AC 

iteration, decoupled AC model or AC OPF. Rather than implementing an OPF, NYISO operates the system to 

high target voltage levels resulting in higher transmission voltages across the transmission system and reduced 

losses. NYISO states that an OPF technology could be used to aid in loss reductions on the transmission system, 

but such an approach would come with significant infrastructure and recurring costs. The transmission system 

should normally be operated within the highest operating levels allowable by equipment ratings and reliability. 

AC OPF and Real-Time Market Look-Ahead 

 PJM employs a DC OPF (an approximation to the AC OPF) with an AC feasibility check, a DC-AC 

iteration approach, and a decoupled AC model with no future plans to modify this approach. CAISO has “fast 

decoupled”9

 its AC power flow analysis, producing linearized loss and shift-factors for optimization in a 

successive iteration approach, to include the non-linearity impact of the power flow model on the optimization 

results. ISO-NE employs a decoupled AC power flow and will deploy a future look-ahead process using MIP 

with an AC feasibility check. MISO reports that it is working on a look-ahead unit-commitment model and 

plans to work on a look-ahead dispatch model. The power flow models will be similar to real-time economic 

dispatch model. SPP uses DC optimization iterating with simultaneous feasibility test. 

AC OPF and Residual Unit-Commitment 

 PJM uses a DC OPF with AC feasibility check, a DC-AC iteration, and a decoupled AC model. CAISO 

uses a fast decoupled AC power flow, producing linearized loss and shift factors for optimization in a 

successive iteration approach to include the non-linearity impact of the power flow model on the optimization 

results. ISO-NE’s optimization iterates between MIP and DC power flow. MISO’s residual unit-commitment 

uses a watch list for linearized real-power flow transmission constraints. SPP employs a DC optimization with 

sensitivity based on watchlist constraints. 

AC OPF and Day-Ahead Market 

 CAISO uses a fast decoupled AC power flow producing linearized loss and shift factors for optimization 

in a successive iteration approach to include the non-linearity impact of the power flow model on the 

optimization results. MISO employs a DC power flow model for the base case conditions. It also employs a 

simultaneous feasibility test to check other power flow constraints (e.g., contingencies). The simultaneous 

feasibility test model is a real power flow model with the real part of the admittance set to zero. If it finds a 

 

9 See Bergen, A. R., and V. Vittal, Power System Analysis, Prentice Hall, New Jersey, 2000.
Page 16 of 42 

violated constraint, it returns a linearized constraint to the optimization problem. PJM employs a DC OPF with 

AC feasibility check, a DC-AC iteration and a decoupled AC model. SPP uses DC optimization iterating with 

simultaneous feasibility test. 

AC OPF and Capacity Market 

 CAISO and SPP have no capacity markets; MISO has plans for a capacity market. NYISO has no AC 

analysis in its capacity market. ISO-NE states that it uses a zonal model in the capacity market auction. PJM 

states that it uses transmission limits, in the form of import limits on a limited number of import limited regions 

of the market, as part of its capacity market model. 

AC OPF and Planning 

 CAISO, MISO and NYISO employ an AC OPF as part of their planning processes. NYISO also has 

utilized a full AC OPF in performing its losses study, which optimized reactive power resources in the New 

York control area with the objective of minimizing losses in the planning horizon system and identifying 

optimal locations for additional reactive compensation. In the future, the NYISO planning department may use 

the ACOPF for further reactive power optimization, as well as developing generation dispatch scenarios and 

determining interface transfer limits. 

 ISO-NE and PJM employ a full AC power flow without optimization. 

Reactive Power Pricing 

 Suppliers providing reactive power are compensated using various pricing methods in the RTOs/ISOs. 

PJM compensates suppliers of reactive power using a call option (or demand charge) payment, which is based 

on a fixed cost allocation method.10 NYISO provides voltage support service (also using a call option or 

demand charge) payments to resources that can be called upon to provide support in real-time market 

operations. ISO-NE employs a cost-based call option payment through its transmission service tariff. SPP and 

MISO currently have no reactive power pricing.11 CAISO is considering measures to minimize active power 

loss as part of the market optimization and a market mechanism for procurement of reactive power. All 

resources are required to be able to meet the power factor range. If the CAISO has to back down a resource’s 

MW to get MVAR, the resource is eligible for opportunity cost. 

 

10 See American Electric Power Service Corp., Opinion No. 440, 88 FERC ¶ 61,141 (1999). 

11 MISO’s reactive power rate design was vacated. See Dynegy Midwest Generation v. Federal Energy Regulatory 

Commission, D.C. Circuit, February 11, 2011. 
Page 17 of 42 

Flexible AC Transmission (FACTS) System Settings 

 FACTS are used by the RTOs/ISO to control the system. In PJM, various FACTS device settings are 

based on real-time and forward looking AC power flow analysis. Phase angle regulators (PARs) are generally 

set in coordination with neighbors to hold schedule flows within a deadband. PARs adjustments are not 

continuous, and PARs are limited because of equipment and maintenance limitations. Static VAR compensator 

(SVC) settings are set to maintain desired 765 and 500 kV voltage profiles and to optimize reactive transfer 

limits. 

In CAISO, DC cable flows (for example, the Trans Bay cable) are optimized based on price differentials 

between terminals and eventually the CAISO may migrate to an explicit DC line model. In ISO-NE, FACTS 

settings are jointly determined by the ISO and transmission owners through offline studies. In MISO, the market 

models do not control or adjust FACTS settings. FACTS such as PARS are set in coordination with neighbors. 

In NYISO, PARs optimization is integrated in the current NYISO unit commitment process in both the dayahead and real-time markets to provide the optimal PAR settings. In SPP, the phase shifter settings can be 

optimized. 
Page 18 of 42 

Appendix. Compilation of Survey Results. 

The information in the below tables is taken directly from survey responses. 

2a) Type of Unit Commitment Models 

Real-Time Market Look-Ahead 

Current Approach 

LR MIP LP 

Notes 

(below) Future Plans 

Estimated 

Annual 

Benefits from 

MIP 

CAISO • (A) MIP is performing well. No plans to 

change models/algorithm. N/A 

ISO-NE • • (B) 

ISO NE is investigating a MIP 

based 2-4 hour look-ahead unitcommitment process. The main 

purpose of this process is to 

facilitate the risk management 

practice in the real-time operation, 

and preposition generators for 

system trending. The unitcommitment solution technique is 

MIP. 

Not specified 

MISO (C) 

MISO is currently implementing a 

real-time look-ahead commitment 

model. It is mixed integer 

programming based. It models 15 

minute intervals for up to a three 

hour period. As such commitment 

decisions can be made as close as 

15 minutes to the real-time period. 

N/A 

NYISO • 

The NYISO has performed an 

initial evaluation of a MIP Unit 

Commitment engine in the Day 

Ahead Market. The NYISO is 

targeting implementation of the 

MIP unit-commitment process 

within the 2011-2013 timeframe for 

use across all optimization 

horizons. 

N/A 

PJM • 

The short term commitment 

models are evolving to produce a 

time-coupled resource dispatch 

trajectory. This is accomplished 

using MIP-based optimization 

engines that are synchronized in 

time. 

$90 million to 

$130 million 

(including 

savings from 

Perfect 

Dispatch) 

SPP • (D) Future market look-ahead will use 

MIP. N/A 
Page 19 of 42 

Notes: 

(A) Prior to April 1, 2009 CAISO used the lagrangian relaxation method based on a zonal 

model. Under its new LMP-based market, in place since April 1, 2009, CAISO uses MIP. This 

was done to improve the quality of the co-optimization of energy and ancillary services, and to 

allow CAISO to include a larger number of transmission constraints in the formulation instead 

of the fewer and more limiting zonal constraints possible using the lagrangian relaxation 

method. 

(B) ISO-NE dose not have an intermediate look-ahead unit-commitment process. It has an 

intra-day reliability unit-commitment process, which adopts the mixed integer programming 

technique. The commitment of fast start units in real time is based on the linear programming 

technique. 

(C) MISO does not at present have real-time market look-ahead unit-commitment software. 

MISO has an intra-day commitment process, but it runs several hours before the real-time 

market. In the real-time market, MISO currently only dispatches already committed units using 

an LP based SCED. 

(D) No real-time market look-ahead in SPP’s current market. 
Page 20 of 42 

Residual Unit Commitment 

Current Approach 

LR MIP LP 

Notes 

(belo

w) Future Plans 

Estimated 

Annual 

Benefits 

from MIP 

CAISO • (A) MIP is performing well no plans to 

change models/algorithm. N/A 

ISO-NE • 

Uncertainties caused by the wind 

power generation, load forecast, 

external transactions, and intermittent 

resources are being considered for 

the future improvement. A robust 

optimization based approach is under 

investigation. 

Not specified

MISO • (B) 

We plan to investigate revised 

objective functions in the RAC 

models. We are also considering 

investigating other modeling changes. 

NYISO • (C) 

The current Residual Unit 

Commitment process at the NYISO is 

integrated within the Forecast Pass 

optimization of the day ahead market. 

This process will be included in the 

implementation of the MIP unitcommitment process as detailed 

below. 

N/A 

PJM • 

MIP is performing well. No plans for 

additional algorithm upgrades at this 

time. 

$90 million 

to $130 

million 

(including 

savings from 

Perfect 

Dispatch) 

SPP (D) Reliability unit commitment (RUC) will 

be using MIP. N/A 

Notes: 

(A) Prior to start of CAISO operations under the new LMP-based market design, CAISO did 

not conduct a residual unit-commitment process. 

(B) MISO has a forward reliability assessment commitment (RAC) model that is run soon after 

the close of the day-ahead market and an intra-day RAC model that is run throughout the day. 

The cost considered in the RAC models is the cost of committing the resources as measured 

by start-up and no-load costs for committed resources as well as the incremental energy costs 

of running the newly committed resources at minimum output. 
Page 21 of 42 

(C) (NYISO) The majority of generation commitment is achieved in the bid pass of the day 

ahead market. The change to a MIP algorithm will provide small incremental production cost 

benefits in the forecast pass of the day ahead market. 

(D) Not applicable in the current SPP market. 
Page 22 of 42 

Day-Ahead Market 

Current Approach 

LR MIP LP 

Notes 

(belo

w) Future Plans 

Estimated 

Annual 

Benefits 

from MIP 

CAISO • (A) No current plan to change the MIP 

approach. $52 million 

ISO-NE • Not specified Not specified

MISO • Not specified Not specified

NYISO • (B) 

The NYISO has performed an 

initial evaluation of a MIP Unit 

Commitment engine in the Day 

Ahead Market. The initial 

evaluation provided promising 

results to both the unitcommitment process and improved 

production cost. The NYISO is 

targeting implementation of the 

MIP unit-commitment process 

within the 2011-2013 timeframe. 

In addition, the NYISO is currently 

undertaking several initiatives to 

enhance the performance of the 

day ahead processes both with 

software and hardware 

enhancements. 

Not specified

PJM • (C) 

MIP is performing well. No plans 

for additional algorithm upgrades 

at this time. 

$60-$100 

million 

SPP (D) 

Day-ahead Market will use MIP for 

unit-commitment and LP for 

dispatch and pricing. 

Notes: 

(A) Prior to start of ISO operations under the new LMP-based market design, the ISO did not 

conduct a day-ahead market and relied on balanced schedules based on the bilateral forward 

market. For comparison purposes, based on a typical industry experience of one percent for 

the Lagrangian duality gap, one can estimate $52 million per year in savings, based on a $15 

million ISO daily objective costs and the current 0.05 percent MIP gap. Recently reduced MIP 

Gap from .5 to .05%. Estimated annual production costs improved efficiency = $7million. 

(B) The evaluation of the MIP unit-commitment process indicated a modest reduction in total 

system production cost and an improved selection of near marginal cost resources. The MIP 

solution tools offer additional flexibility to support enhanced market functionality. 

(C) The implementation of MIP-based commitment in the day-ahead market has significantly 

reduced day-ahead market uplift and had reduced total production costs by between $60 - 

$100 million annually. 
Page 23 of 42 

(D) Not applicable in the current SPP market. 
Page 24 of 42 

Capacity Market 

Current Approach 

LR MIP LP 

Notes 

(belo

w) Future Plans 

Estimat

ed 

Annual 

Benefit

s from 

MIP 

CAISO (A) No current plans to develop a centralized 

capacity market N/A 

ISO-NE • (B) 

The capacity market is being redesigned, and 

the future market clearing may adopt the 

mixed integer linear programming technology. 

Not 

specifie

d 

MISO • (C) 

MISO is investigating a more forward looking 

capacity market with possible zonal 

requirements. Zones will have import and 

export limits. 

N/A 

NYISO • Continue with LP approach; no issues with 

execution time or accuracy. N/A 

PJM • MIP is performing well. No plans for additional 

algorithm upgrades at this time. 

N/A 

(original 

design) 

SPP (D) Not in scope for future market. N/A 

Notes: 

(A) CAISO does not have a centralized long-term capacity market. 

(B) The methodology for the ISO-NE capacity market clearing is the mixed integer nonlinear 

programming that searches for the global optimal solution. 

(C) The MISO capacity market is a simple auction model with a single period and zone. It is a 

simple intersection of the supply offer curve with the demand. As such it can be viewed as a 

simple LP. 

(D) Not applicable in the current SPP market. 
Page 25 of 42 

2b) Unit Commitment Characteristics 

Modeling of Flexibility in Resource Limits (e.g. Violation Relaxation Limits on Flowgates, Eco 

Min, Eco Max, etc) 

 Current Approach Future Plans 

CAIS

O 

All resource-related limits are hard limits except 

for daily energy use limits. Flowgate constraints 

are soft constraints.

No future plans to change the 

process. 

ISONE 

In ISO-NE, the relaxation of transmission 

constraints is being done in a separate process, 

but does include very high penalties. 

Adaptive transmission line 

rating is being considered for 

future implementation. 

MISO 

MISO software uses high penalty prices on 

constraint violations to enforce limits. Presently, 

some transmission limits that cannot be enforced 

are relaxed to just over the flow that can be 

achieved prior to a second run to develop shadow 

prices in these constraints. . MW limits for 

resources such as generators depend upon operating 

conditions. One set of limits may be used during 

normal operations. During maximum demand 

situations in which MISO experiences difficulty 

satisfying demand, Emergency Maximum limits may 

be employed. Emergency Minimum limits may be 

used when MISO experiences difficulty satisfying 

minimum operating limits. Emergency operations 

allow operation beyond economic limits used in normal 

operations and are based on emergency offer segments 

of resources. The resource limits selected based on 

conditions are enforced by setting high penalties on 

violations.

MISO plans to remove the 

constraint relaxation on 

transmission constraints that 

cannot be enforced and simply 

use the penalty price in trying 

to enforce the limit and 

developing the shadow prices. 

NYIS

O 

In February 2005, as part of the SMD 2.0 

implementation, NYISO implemented demand 

curves for Operating Reserve, Regulation, and 

Transmission Constraints that incorporate the 

assigned product shortage cost into the applicable 

market clearing prices. Shortage values need to 

reflect the value of reserves during shortage 

conditions, consistent with operational practice 

and reserve scheduling requirements. With 

appropriate shortage values, shortage pricing 

ensures appropriate pricing and scheduling results 

when the desired amount of reserves or regulation 

is unavailable. 

NYISO has a project underway 

to re-assess the operation of 

the current reserve and 

regulation shortage values and 

to confirm the continued 

applicability of the current set 

points In addition, it will 

consider the need for additional 

shortage values to determine 

prices during shortage 

conditions. 

PJM 

PB constraint penalty= $1000/MWh; Ramp 

constraint penalty = $50,000/MWh; Emergency 

MW constraints= $5,000/MWh. Economic MW 

limits are dependent on operating conditions. 

Normal operations = $5,000/MWh; emergency 

Moving toward adaptive 

transmission constraint model 

where penalties are adapted 

based on rate of change of flow 

vs. limit 
Page 26 of 42 

operations will allow economic limits to be violated 

based on emergency offer segments of unit which 

can include negative offers for min limits. 

Transmission constraints default to $1000/MWh 

but are adapted based on dispatch conditions. 

The penalty adaptation is semi-automated and 

has the objective to set limit at the upper bound of 

seasonal physical dispatch alternatives (i.e. it is a 

function of DFAX and resource offer relative the 

unconstrained dispatch marginal price) Generally 

lower voltage level facilities have higher penalty 

levels because there are fewer resource dispatch 

options. 

Also moving toward adaptive 

generation modeling which 

modifies economic operating 

range dynamically based on 

unit dispatch trajectory, etc. 

SPP 

Dispatching of resources includes penalty factors 

for violation of resource limits on flowgates, ramp 

rates, balancing. 

Market model includes a very 

high penalty parameter for 

relaxing resource limits. 

Penalties for different 

constraints 

will be determined during the 

implementation. 

A few on-going prototyping 

activities for transmission 

constraint pricing are under 

review: 

- MW dependent penalty price 

curve 

- Sub-gradient base 

transmission pricing 

- Convex-Hull approach 

 
Page 27 of 42 

Ramp Rate Modeling 

 Current number of ramp-rates per generator Future Plans 

CAIS

O 

Multiple (dynamic rates based on MW output of 

generator) 

No future plans to change the 

process. 

ISONE 

Single - The ramp rate in the real-time dispatch 

is taken from one point of the multiple-ramp rate 

curve. 

The average ramp rate for the 

dispatch interval will be 

implemented in the real-time 

dispatch. 

MISO 

Single in day-ahead. In real-time, allows 

resources to submit a ramp rate curve, and 

different ramp up, ramp down and bidirectional 

(the latter is only for AGC units) ramp rate limits. 

MISO is considering allowing 

resources to submit different 

ramp up, ramp down and 

bidirectional ramp rate limits in 

the day-ahead market. MISO is 

also considering modeling 

emergency ramp limits. 

NYIS

O 

Three segment ramp rate for energy in dayahead and in real-time. 

The NYISO is undertaking a 

project to evaluate the need and 

practically of multi-segment ramp 

rates for ancillary service 

products. Multi stage thermal 

units have indicated potential 

complications with both 

maintaining a constant ramp rate 

across their output ranges for 

regulation, as well as 

complications regulating in 

ranges requiring duct firing. This 

project will evaluate and 

determine the exact needs of 

resources for this ability. 

PJM Up to 10 different ramp rates for different MW 

operating ranges. 

We are working to implement 

enhancements to allow ramp 

rates be different depending on 

whether the unit is ramping up or 

down. 

SPP Multiple ramp rates for dispatch purposes only. 

MW based ramp rate curve per 

generator for commitment. 

Multiple ramp rate curve types 

(ramp up, ramp down, ramp 

bidirectional), for dispatch. 
Page 28 of 42 

Co-optimization of Energy and Ancillary Services 

 Current approach Future Plans 

CAIS

O 

Co-optimization of energy, contingency 

reserves, and regulation. 

Currently, in the real-time Energy 

and A/S is co-optimized on a 15 

minute interval basis in the real-time 

unit commitment (RTUC) process. 

The A/S awards are binding in the 

RTUC, but the energy dispatch in 

the RTUC is not. Instead, the RTUC 

energy dispatch is re-optimized on 5 

minute basis in the real-time market. 

In the future we may consider cooptimizing on 5 minutes basis to 

make A/S and energy binding on 

same interval. 

ISONE Co-optimization of energy and reserves only. 

Cost/benefit analysis of cooptimization with regulation will be 

conducted in the future. 

MISO Co-optimization of energy, contingency 

reserves, and regulation No response 

NYIS

O 

Co-optimization of energy, contingency 

reserves, and regulation: The NYISO unitcommitment process performs a 

simultaneous co-optimization solution for 

energy, reserves and regulation which is 

performed in the day ahead market and in 

the real-time market. This practice has been 

in place for the day ahead market since 1999 

and for the real-time market since 2005. 

No response 

PJM 

Current process performs co-optimization of 

energy and reserve to make 

reserve/regulation assignments for each 

hour, 30 minutes before the hour. The realtime 5 minute dispatch will incrementally 

modify reserve and regulation assignments 

which is a limited form of co-optimization 

however we do not actually do simultaneous 

optimization of energy and reserves every 5 

minute period 

Current plan is to upgrade to a 5 

minute Co-optimization of energy, 

contingency reserves, and regulation 

on May 1, 2011 

SPP N/A to current market 

Co-optimization of energy, 

contingency reserves, and 

regulation. 
Page 29 of 42 

Transmission Switching 

 Current approach Future Plans 

CAIS

O 

Currently some special protection schemes that do not 

affect generation or load are considered in the security 

constrained unit-commitment (SCUC)/security 

constrained economic dispatch (SCED) optimization. 

The ISO is in initial stages 

of investigating using 

optimization to perform 

post-contingency 

corrective actions. 

ISONE Special protection schemes No response 

MISO None No response 

NYIS

O 

Special protection schemes. NYISO captures 

transmission switching operations in the commitment 

and dispatch optimization processes to ensure the 

most efficient resource utilization is available prior, 

during and after the outage. 

No response 

PJM 

Special protection schemes. Also, semi-automated online powerflow analysis with confirmation by 

engineering staff considers available switching options 

and/or bus reconfiguration to alleviate overloads to 

avoid off-economic dispatch and/or to avoid emergency 

load management. 

New EMS in 2011 will 

allow further automation of 

the process. 

SPP N/A in current market Not planned for future 

markets 

Combined-Cycle Generator Modeling 

 Current approach Future Plans 

CAISO 

On December 7, 2010 the CAISO 

implemented testing its new multi-stage 

generation modeling approach, which 

models each configuration in a plant as a 

separate resource accounting for the 

cost/time dependencies between the 

different plant configurations. 

No response 

ISO-NE Resource divided into approximate 

aggregate configurations No response 

MISO 

Participants with combined cycle 

generators can model different 

configurations as generators with 

characteristics that depend upon the 

configuration. The participant must specify 

which configuration it is offering into the 

market. Only a single configuration may be 

offered for a combined cycle generator. 

MISO is investigating enhanced 

modeling of the combined cycle 

generators in which the unitcommitment model will select which 

configuration to use. In essence 

additional integer variables will be 

used to model such decisions. 

NYISO 

The NYISO modeling utilizes a gas 

turbine/steam turbine coupled model(s) to 

represent the operating modes of the plant 

NYISO will be moving towards a MIP 

methodology in the 2011-2013 

timeframe as part of the evaluation 
Page 30 of 42 

for commitment and dispatch of combined 

cycle generation units. The models allows 

for the representation of individual gas 

turbine commitment costs to the 

optimization processes and captures the 

combined unit operating characteristics for 

the dispatch tools. 

and implementation process the 

NYISO will review the potential for 

individual unit configuration for 

combined-cycle generators. 

PJM 

Several modeling approaches are available 

to resource owners. Optimization can 

accommodate multiple/conditional offers. 

MIP is performing well. No plans for 

additional algorithm upgrades at this 

time. 

SPP Same as all generators 

Each configuration modeled as a 

unit and transition between 

configurations are modeled. 
Page 31 of 42 

Dispatchable Load Modeling 

 Current approach Future Plans 

CAIS

O 

Modeled similar to a generator, with similar 

parameters. 

Considering further modeling 

enhancements for demand 

response. 

ISONE 

The dispatchable loads are modeled similar to 

generators without commitment type of 

parameters such as minimum up and down 

time. 

Commitment type of parameters 

for dispatchable loads may be 

introduced. 

MISO Modeled similar to a generator, with similar 

parameters. No response 

NYIS

O 

The NYISO approaches dispatchable load 

modeling in three methods. First, our day 

ahead demand response program allows for 

the same full functionality as generator bidding 

to schedule economic demand reductions in 

the day ahead market. Second, it allows for 

price cap functionality allowing market 

participants the ability to schedule their load 

purchases using predetermined limits. Third, 

allows dispatchable load the same full 

functionality as generator bidding to schedule 

economic demand reductions in the real time 

market. 

No response 

PJM 

Modeled similar to a generator, with similar 

parameters. Note that loads can choose to be 

modeled nodally (i.e. single substation) and 

enter complete set of offer parameters 

comparable with generators. Aggregated 

loads across multiple substations are also 

permitted but the distribution of the load across 

the substations must be specified and all 

substations in the aggregate must be in the 

same transmission zone. 

Plan to upgrade load forecast, 

powerflow, optimization, etc. to 

accommodate widespread 

development of distributed priceresponsive demand and alternative 

technology (i.e. storage, PHEV). 

Most of the effort is in upgrading 

performance. The load model and 

fundamental MIP algorithm is to be 

able to support widespread 

distribute resource penetration 

based on current assessment. 

SPP Modeled similar to a generator, with similar 

parameters. No response 
Page 32 of 42 

Dispatchable Load Modeling 

Current Approach 

Pumpe

d 

Storage 

Bidding 

Endogenousl

y Optimized Other Future Plans 

CAIS

O • 

Further modeling 

enhancements for different 

types of storages are being 

considered. 

ISONE 

Bids for pumping and 

generation from a pumpstorage unit are optimized 

independently. 

No response 

MISO 

For pumped storage, the 

participant can decide in 

which intervals the resource 

can be scheduled to 

generate and which 

intervals it can be 

scheduled to pump. In the 

intervals in which it can be 

scheduled to generate, the 

participant can submit an 

offer like any other 

generator. In intervals in 

which it can be scheduled to 

pump, the participant can 

submit a price sensitive 

demand bid. 

No response 

NYIS

O • 

NYISO market offers the 

capability to economically 

schedule the production and 

recharge cycles of pump 

storage facilities based 

upon the market clearing 

prices. 

The NYISO is targeting a 

project to evaluate a full 

co-optimization of physical 

and financial offers from 

storage devices, including: 

recharge time, minimum 

cycle time arbitrage 

spreads, etc. 

PJM • No response 

SPP Will support pumped 

storage bidding 
Page 33 of 42 

2) Unit Commitment Characteristics 

Modeling of Flexibility in Resource Limits (e.g. Violation Relaxation Limits on Flowgates, Eco 

Min, Eco Max, etc) 

 Current Approach Future Plans 

CAIS

O 

All resource-related limits are hard limits except 

for daily energy use limits. Flowgate constraints 

are soft constraints. No future plans to change 

the process. 

ISONE 

In ISO-NE, the relaxation of transmission 

constraints is being done in a separate process, 

but does include very high penalties. 

Adaptive transmission line rating 

is being considered for future 

implementation. 

MISO 

MISO software uses high penalty prices on 

constraint violations to enforce limits. Presently, 

some transmission limits that cannot be 

enforced are relaxed to just over the flow that 

can be achieved prior to a second run to 

develop shadow prices in these constraints. 

MISO plans to remove the 

constraint relaxation on 

transmission constraints that 

cannot be enforced and simply 

use the penalty price in trying to 

enforce the limit and developing 

the shadow prices. 

NYIS

O 

In February 2005, as part of the SMD 2.0 

implementation, NYISO implemented demand 

curves for operating reserve, regulation, and 

transmission constraints that incorporate the 

assigned product shortage cost into the 

applicable market clearing prices. Shortage 

values need to reflect the value of reserves 

during shortage conditions, consistent with 

operational practice and reserve scheduling 

requirements. With appropriate shortage 

values, shortage pricing ensures appropriate 

pricing and scheduling results when the desired 

amount of reserves or regulation is unavailable. 

NYISO has a project underway to 

re-assess the operation of the 

current reserve and regulation 

shortage values and to confirm 

the continued applicability of the 

current set points In addition, it 

will consider the need for 

additional shortage values to 

determine prices during shortage 

conditions. 

PJM 

PB constraint penalty= $1000/MWh; Ramp 

constraint penalty = $50,000/MWh; Emergency 

MW constraints= $5,000/MWh. Economic MW 

limits are dependent on operating conditions. 

Normal operations = $5,000/MWh; emergency 

operations will allow economic limits to be 

violated based on emergency offer segments of 

unit which can include negative offers for min 

limits. Transmission constraints default to 

$1000/MWh but are adapted based on dispatch 

conditions. The penalty adaptation is semiautomated and has the objective to set limit at 

the upper bound of seasonal physical dispatch 

alternatives (i.e. it is a function of DFAX and 

resource offer relative the unconstrained 

dispatch marginal price) Generally lower 

Moving toward adaptive 

transmission constraint model 

where penalties are adapted 

based on rate of change of flow 

vs. limit 

Also moving toward adaptive 

generation modeling which 

modifies economic operating 

range dynamically based on unit 

dispatch trajectory, etc. 
Page 34 of 42 

voltage level facilities have higher penalty levels 

because there are fewer resource dispatch 

options. 

SPP 

Dispatching of resources includes penalty 

factors for violation of resource limits on 

flowgates, ramp rates, balancing. 

Market model includes a very 

high penalty parameter for 

relaxing resource limits. 

Penalties for different constraints 

will be determined during the 

implementation. A few on-going 

prototyping activities for 

transmission constraint pricing 

are under review: 

- MW dependent penalty price 

curve 

- Sub-gradient base transmission 

pricing 

- Convex-hull approach 

 
Page 35 of 42 

4 AC Power Flow Models 

 4a AC Power Flow Models in Operation 

AC OPF and Real-Time Economic Dispatch 

Current Approach 

DC 

OPF 

with AC 

feasibili

ty 

check 

DC-AC 

Iteratio

n 

Decouple

d AC 

model 

used 

AC 

OP

F Other None 

Notes 

(below) Future Plans 

CAISO • (A) None 

ISO-NE • 

ISO NE is 

conducting 

research on the 

risk-based 

security in 

SCED. 

MISO • (B) None 

NYISO • (C) None 

PJM • • None 

SPP • (D) None 

Notes: 

(A) AC based on last 15 minute linearized loss and shift-factors unless there is a contingency 

or an event is declared, in which case the AC is based on the current state of the system. 

(B) The state estimator model has an AC power flow model incorporated. The real-time 

market uses a linearization of the real power part of the power flow model with a correction of 

the limits for reactive flows. 

(C) The NYISO states that rather than implementing an OPF, NYISO operates the system to 

high target voltage levels resulting in higher transmission voltages across the transmission 

system and reduced losses. Pursuing loss reductions through target voltage levels 

complements existing NYISO and transmission owner reliability practices. An OPF technology 

could be used to aid in loss reductions on the transmission system but would come with 

significant infrastructure and recurring costs. The expected outcome of OPF technology is that 

the transmission system should normally be operated at the highest operating levels allowable 

by equipment ratings. (D) DC optimization interacted with AC real-time contingency analysis. 
Page 36 of 42 

AC OPF and Real-Time Market Look-Ahead 

Current Approach 

DC 

OPF 

with AC 

feasibili

ty 

check 

DC-AC 

Iteratio

n 

Decouple

d AC 

model 

used 

AC 

OP

F Other None 

Notes 

(below) Future Plans 

CAISO • (A) None 

ISO-NE • 

Future lookahead process 

will use MIP with 

AC feasibility 

check. 

MISO • 

Working on lookahead unitcommitment 

model and plans 

to work on a 

look-ahead 

dispatch model. 

The power flow 

models will be 

similar to realtime economic 

dispatch model. 

NYISO • (B) None 

PJM • • • None 

SPP • (C) None 

Notes: 

(A) Fast decoupled AC power flow producing linearized loss and shift-factors for optimization 

in a successive iteration approach to include the non-linearity impact of the power flow model 

on the optimization results. 

(B The NYISO states that rather than implementing an OPF, NYISO operates the system to 

high target voltage levels resulting in higher transmission voltages across the transmission 

system and reduced losses. Pursuing loss reductions through target voltage levels 

complements existing NYISO and transmission owner reliability practices. An OPF technology 

could be used to aid in loss reductions on the transmission system but would come with 

significant infrastructure and recurring costs. The expected outcome of OPF technology is that 

the transmission system should normally be operated at the highest operating levels allowable 

by equipment ratings.) (C) DC optimization iterating with MW only simultaneous feasibility 

test. 
Page 37 of 42 

AC OPF and Residual Unit-Commitment 

Current Approach 

DC 

OPF 

with AC 

feasibili

ty 

check 

DC-AC 

Iteratio

n 

Decouple

d AC 

model 

used 

AC 

OP

F Other None 

Notes 

(below) Future Plans 

CAISO • (A) None 

ISO-NE • (B) None 

MISO • (C) None 

NYISO • (D) None 

PJM • • • None 

SPP • 

DC optimization 

with sensitivity 

based on 

watchlist 

constraints. 

Notes: 

(A) Fast decoupled AC power flow producing linearized loss and shift-factors for optimization 

in a successive iteration approach to include the non-linearity impact of the power flow model 

on the optimization results. 

(B) Optimization iterates between MIP and DC power flow. 

(C) Residual unit-commitment uses watchlist transmission constraints. The constraints are 

linearized real-power flow constraints. 

(D) The NYISO states that rather than implementing an OPF, NYISO operates the system to 

high target voltage levels resulting in higher transmission voltages across the transmission 

system and reduced losses. Pursuing loss reductions through target voltage levels 

complements existing NYISO and transmission owner reliability practices. An OPF technology 

could be used to aid in loss reductions on the transmission system but would come with 

significant infrastructure and recurring costs. The expected outcome of OPF technology is that 

the transmission system should normally be operated at the highest operating levels allowable 

by equipment ratings. 
Page 38 of 42 

AC OPF and Day-Ahead Market 

Current Approach 

DC 

OPF 

with AC 

feasibili

ty 

check 

DC-AC 

Iteratio

n 

Decouple

d AC 

model 

used 

AC 

OP

F Other None 

Notes 

(below) Future Plans 

CAISO • (A) None 

ISO-NE • None 

MISO • (B) None 

NYISO • (C) None 

PJM • • • None 

SPP • 

DC optimization 

iterating with MW 

only 

simultaneous 

feasibility test 

Notes: 

(A) Fast decoupled AC power flow producing linearized loss and shift-factors for optimization 

in a successive iteration approach to include the non-linearity impact of the power flow model 

on the optimization results. 

(B) The day-ahead market contains a DC power flow model for the base case conditions. It 

also employs a simultaneous feasibility test to check other power flow constraints (e.g. 

contingencies). The simultaneous feasibility test model is a real-power flow model with the 

real part of the admittance set to zero. If it finds a violated constraint, it returns a linearized 

constraint to the optimization problem. 

(C) NYISO states that OPF technology could be used to aid in loss reductions on the 

transmission system but would come with significant infrastructure and recurring costs. The 

expected outcome of OPF technology is that the transmission system should normally be 

operated at the highest operating levels allowable by equipment ratings. Operating the system 

to high target voltage levels results in higher transmission voltages across the transmission 

system and reduced losses. NYISO states that pursuing losses reductions through target 

voltage levels complements existing NYISO and transmission owner reliability practices. 
Page 39 of 42 

AC OPF and Capacity Market 

Current Approach 

DC 

OPF 

with AC 

feasibili

ty 

check 

DC-AC 

Iteratio

n 

Decouple

d AC 

model 

used 

AC 

OP

F Other None 

Notes 

(below) Future Plans 

CAISO • None 

ISO-NE • (A) None 

MISO • None 

NYISO • None 

PJM • (B) None 

SPP • None 

Notes: 

(A) A zonal model rather than detailed network model is considered in the capacity market 

auction. 

(B) Reduced form transmission limits produced in the form of import limits are created on a 

limited number of import limited regions of the market. 

AC OPF and Planning 

Current Approach 

DC 

OPF 

with AC 

feasibili

ty 

check 

DC-AC 

Iteratio

n 

Decouple

d AC 

model 

used 

AC 

OP

F Other None 

Notes 

(below) Future Plans 

CAISO • None 

ISO-NE • (A) Will consider AC 

OPF 

MISO • None 

NYISO • (B) None 

PJM • (A) None 

SPP • None 

Notes: 

(A) Full AC model without optimization. 

(B) The NYISO has utilized a full AC OPF in performing the NYISO losses study. That study 

optimized reactive power resources in the New York control area with the objective of 
Page 40 of 42 

minimizing losses in the planning horizon system and identifying optimal locations for 

additional compensation. 

In the future, the NYISO planning department may use the AC OPF for further reactive power 

optimization as well as developing generation dispatch scenarios and determining interface 

transfer limits. 
Page 41 of 42 

 4b Pricing and Operations Related to AC Power Flow Markets 

Reactive Power Pricing and/or Payments 

Current Approach 

Opportun

ity cost 

Options 

paymen

t based 

on AEP 

method 

Other 

options 

payme

nt 

Reactiv

e LMP 

Oth

er None

Notes 

(below) Future Plans 

CAISO • (A) 

Considering 

market 

mechanism for 

procurement of 

reactive power 

ISO-NE • (B) 

MISO • None 

NYISO • (C) None 

PJM • None 

SPP • None 

Notes: 

(A) All resources are supposed to be able to meet power factor range. If the ISO has to back 

resource MW to get MVAR, the resource is eligible for opportunity cost. Utilize reliability-mustrun resources for this purpose. 

(B) Cost-based payment through transmission tariff. 

(C) Provides voltage support service payments to resources that can be called upon to 

provide support in real-time market operations. 
Page 42 of 42 

Flexible AC Transmission System Settings 

Describe how FACTS settings are determined Future Plans 

CAISO 

DC cable flows are optimized based on price differentials 

between terminals (i.e.,Trans Bay cable) 

May eventually 

migrate to an explicit 

DC line model 

versus current 

implicit DC model. 

ISO-NE FACTS settings are jointly determined by the ISO and 

transmission owners through offline studies. None 

MISO The market models do not control or adjust FACTS settings. None 

NYISO 

Phase angle regulator (PAR) optimization is integrated in the 

current NYISO unit commitment process which is used in 

day-ahead and real-time markets and provides the optimal 

PAR settings to aid in the reduction of congestion. This 

process will be retained as the NYISO moves towards a MIP 

unit-commitment process. 

None 

PJM 

Various FACTS device settings are based on real-time and 

forward looking AC power flow analysis. 

PARs are generally set in coordination with neighbors to 

hold schedule flows within a deadband. Note PAR 

adjustments are not continuous as there are limited PAR 

moves available throughout the operating day because of 

equipment and maintenance limitations. 

SVC settings are set to maintain desired 765 and 500 kV 

voltage profile and to optimize reactive transfer limits. 

None 

SPP Phase shifter settings can be optimized None