**Supplemental Comments on Linkage** **s between Projecte d 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 Revisi ons to CSAPR 11 28 1 1” ) to projected and historical utilization (attachment C of “ Updated AEP Comments on Proposed Revisions to CSAPR 11 28 1 1” ) for units not operating within EPA’s IPM runs used in the development of CSAPR state budgets

. The reliability and m ust 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 dispatch ed 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 certai n coal units are offl ine and the AEP control area ’ s load warrant s
. 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 fil led through eit her 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 generat ion is not online in one of the AEP control area sub

- region s 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, Ri verside 2, Knox Lee 5 and Wilkes 2 & 3 are some of the units that are frequently utilized to cover firm capacity and transfer limit requirement s. Whe n possible , these units will also serve a double purpose by satisfying the must run requirement s and loss of largest load contingencies as well.

T here 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 utilitie s and the Southwest Power Pool say that the biggest impediment to economic dispatch is constraints on the transmission system. Transmission constraints can prevent e fficient 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 curtai led. ” 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 rate s 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 . I n 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 muc h 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 proj ected 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.

B ased 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 rece nt historical period to determine what portion of the operatio n 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 % o peration 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 c an potentially be used to adjust

1 The Joint Board for the Sout h 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

. T his is a very conservative estimate of the non

- economic factors contributing to dispat ch because once a unit is required to be online for capacity or reliability pur poses, 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 a ddition, supplemental generation from these must run resources is often required for load

-following purposes

. H owever, this aspect of reliability need cannot be adequately quantified by AEP.

**P JM** 
Three units within AEP’s previous attachment C, Muski n gum 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 20 12 and h ave historical ly operated at substantial levels. O nly 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 l ater reconnect to help restore the grid. T he 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 o peration 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 transmi ssion interconnection, running units to meet capacity needs is not currently a constraint within the PJM region.**A ppendix**  **A Percent of Operation**  **Reflected on Attachment C Due**  **Solely to**  **Reliability and**  **Capacity Constraints** 

**State Un**  **it % Annual**  **Ope rati**  **on Attri**  **bute d to Ca**  **paci ty/** **RMR %**  **Oz one** **Se as**  **on Ope**  **rati on**  **Attri bute**  **d to Capa ci**  **ty/ RM**  **R** LA Ar se nal Hill 5 56% 54% LA Li eberm an 1 99% 99% LA Li eberm an 2 99% 99% LA Li eberm an 3 87% 86% LA Li eberm an 4 89% 89% OH Mu skin gum Riv

er 1 40% 41% OH Mu skin gum Riv

er 2 0% 0% OH Pi cway9 0% 0% OK Nort heas te rn 2 62% 58% OK Riv

ers id e 2 56% 37% OK So ut hwes te rn 1N 82% 77% OK So ut hwes te rn 1S 82% 77% OK So ut hwes te rn 2 81% 76% OK So ut hwes te rn 3 43% 23% OK Tu lsa2 70% 58% OK Tu lsa3 96% 96% OK Tu lsa4 75% 60% TX Kn oxLee 2 96% 96% TX Kn oxLee 3 96% 96% TX Kn oxLee 4 89% 89% TX Kn oxLee 5 49% 35% TX Lone Sta r 1 100% 100% TX Wi lk es1 73% 61%