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.”

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 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

 The Joint Board for the South Region. “Study and Recommendations
Regarding Security Constrained Economic Dispatch,” Docket No.
AD05-13-000.  July 11, 2006.

