Supplemental Comments on Linkages between Projected and Historical Unit Operation and 

Reliability Constraints

The purpose of this memo is to further link AEP’s system reliability requirements (attachments

A and B of “Updated AEP Comments on Proposed Revisions to CSAPR 11 28 11”) to projected 

and historical utilization (attachment C of “Updated AEP Comments on Proposed Revisions to 

CSAPR 11 28 11”) for units not operating within EPA’s IPM runs used in the development of 

CSAPR state budgets. The reliability and must run (RMR) requirements are developed by AEP’s 

transmission group and are approved by Southwest Power Pool (SPP) or PJM as part of AEP’s 

system restoration and operating plan. While attachments A and B describe certain conditions 

under which units must run for reliability purposes, there are distinct differences between how 

units are committed and dispatched in SPP versus PJM. As such, this memo will highlight the 

differences in these areas and the relevant constraints requiring units to operate. Appendix A at 

the end of this memo provides the percentage of generation attributed SOLELY to reliability 

purposes. These percentage factors can be multiplied by the heat input previously provided in 

Attachment C, in order to adjust the heat input to only capture operation for reliability 

purposes. In all cases, this is a conservatively low assessment of the units operation for 

reliability reasons.

SPP

Within SPP, AEP is required to ensure that specific gas units are running when certain coal units 

are offline and the AEP control area’s load warrants. Certain gas units are also required to be 

online for system support and blackstart restoration plans. Next day system load is required to 

be covered using firm capacity resources and can be filled through either day-ahead, firm 

purchases or by AEP generation that is planned to be online. There are also transfer limits that 

must be met to ensure that too much generation is not online in one of the AEP control area 

sub-regions and that AEP is able to cover the loss of the largest unit online in each sub-region as 

a “first contingency” planning process. Northeastern 2, Riverside 2, Knox Lee 5 and Wilkes 2 & 

3 are some of the units that are frequently utilized to cover firm capacity and transfer limit 

requirements. When possible, these units will also serve a double purpose by satisfying the 

must run requirements and loss of largest load contingencies as well.

There are limits to capacity purchases due to transmission constraints and availability, requiring 

units within the AEP system to be frequently online for capacity reasons. As an example, while 

units such as Lone Star and Tulsa 3 are not explicitly listed within the reliability criteria, they are 

frequently utilized within periods of peak demand to satisfy capacity requirements within SPP

due to transmission transfer limits.
According to The South Joint Board for the Study of Security Constrained Economic Dispatch, a 

FERC chartered panel, there are significant limitations to economic dispatch within the SPP 

region. “Because of transmission limitations in the South, transmission dependent utilities and 

the Southwest Power Pool say that the biggest impediment to economic dispatch is constraints 

on the transmission system. Transmission constraints can prevent efficient generation 

resources from being dispatched. These parties say they are frequently unable to access 

economic sources because of transmission limitations and often forgo economic transactions 

because of a concern that the transaction could be curtailed.”

1

The forecasted 2012 operation provided by AEP in attachment C to our previous comments was 

modeled using the GenTrader application developed by Power Costs Inc (PCI). To model the 

AEP system the GenTrader application requires various unit-specific operating and cost inputs. 

Other inputs include forecasted internal load, contracts and estimated market prices. The 

hourly unit generation position is based on market prices and each unit’s physical operating 

constraints, including heat rates, ramp rates and unit minimums. Most importantly, in contrast 

to IPM, GenTrader is able to incorporate the reliability requirements and various “security 

zones” within AEP’s control areas in SPP to ensure that the correct resources are online to meet 

both reliability and capacity requirements for each hour. In effect, the model takes into account

transmission constraints within the SPP region thru the use of security zones. The combination 

of all these factors along with a chronological dispatch makes GenTrader a much more precise 

predictor of unit operation than IPM. As such, AEP feels the GenTrader projected 2012 

operation is the best indicator of expected unit performance. Historical heat-input projections 

were also included as a basis for justifying that the projected 2012 operation is “reasonable” as 

compared to 2010 operation. While it has been noted that certain units are projected to run at 

greater than 2010 levels in 2012, this can be attributed to the tightening of capacity markets 

requiring additional firm capacity from within the AEP system.

Based on EPA’s concern that some of the heat input previously provided in attachment C could

be attributed solely to economic dispatch (which theoretically should have been picked up by 

IPM), AEP reviewed the most recent historical period to determine what portion of the 

operation in attachment C of AEP’s previous filing was solely attributed to reliability and 

capacity constraints during a recent 12 month period (October 2010 to September 2011). AEP 

calculated the % operation that could be attributed SOLELY to reliability and capacity 

constraints during this period based on the minimum load of units needed to serve these 

requirements (see appendix A of this document). This data can potentially be used to adjust 

 

1

The Joint Board for the South Region. “Study and Recommendations Regarding Security Constrained Economic 

Dispatch,” Docket No. AD05-13-000. July 11, 2006.
the projected heat input for these units previously provided in attachment C of AEP’s 

comments. The adjusted heat input can then be used to adjust individual state budgets. This is 

a very conservative estimate of the non-economic factors contributing to dispatch because 

once a unit is required to be online for capacity or reliability purposes, additional generation 

from these units is often less costly than units with lower long run economic and operational 

costs due to the avoidance of start-up and ramping costs with the utilization of units that are 

already online. In addition, supplemental generation from these must run resources is often 

required for load-following purposes. However, this aspect of reliability need cannot be 

adequately quantified by AEP.

PJM

Three units within AEP’s previous attachment C, Muskingum River 1, Muskingum River 2 and 

Picway 9 were projected not to run within IPM under the CSAPR policy case. However, AEP’s 

forecasting indicates that these units will all operate during 2012 and have historically operated 

at substantial levels. Only one of the units, Muskingum River 1, is required to operate for 

system reliability, based on its Automatic Load Reject (ALR) capability, which allows it to 

disconnect from the grid in case of system failure and later reconnect to help restore the grid. 

The projection of Muskingum River 1 operation for reliability purposes reflects Muskingum 

River 1’s operation at minimum load to meet this reliability requirement. Thus, the projection 

of reliability operation for Muskingum River 1 is very conservative due to its ability to overcome 

start up costs in displacement of more economic generation and ability to follow load.

Due to the more developed nature of the PJM market and a more robust system of 

transmission interconnection, running units to meet capacity needs is not currently a constraint 

within the PJM region.
Appendix A

Percent of Operation Reflected on Attachment C

Due Solely to Reliability and Capacity Constraints

State Unit

% Annual Operation 

Attributed to Capacity/RMR

% Ozone Season Operation 

Attributed to Capacity/RMR

LA Arsenal Hill 5 56% 54%

LA Lieberman 1 99% 99%

LA Lieberman 2 99% 99%

LA Lieberman 3 87% 86%

LA Lieberman 4 89% 89%

OH Muskingum River 1 40% 41%

OH Muskingum River 2 0% 0%

OH Picway 9 0% 0%

OK Northeastern 2 62% 58%

OK Riverside 2 56% 37%

OK Southwestern 1N 82% 77%

OK Southwestern 1S 82% 77%

OK Southwestern 2 81% 76%

OK Southwestern 3 43% 23%

OK Tulsa 2 70% 58%

OK Tulsa 3 96% 96%

OK Tulsa 4 75% 60%

TX Knox Lee 2 96% 96%

TX Knox Lee 3 96% 96%

TX Knox Lee 4 89% 89%

TX Knox Lee 5 49% 35%

TX Lone Star 1 100% 100%

TX Wilkes 1 73% 61%