Page 1 of 7 October 8, 2014 

### SPP’S RELIABILITY IMPACT ASSESSMENT

OF THE EPA’S PROPOSED CLEAN POWER PLAN

Background 1

In its recently released proposed Clean Power Plan (CPP) rule , the U.S. E nvironmental P rotection

A gency (EPA) proposes to cut existing power plant carbon emissions 30% by the year 2030 , from 2005

levels

. As currently proposed, t he CPP will be implemented through state

- developed plans that meet

state

- specific carbon reduction goals set by the EPA

. Th e CPP offers flexibility for states to rely on a number of options to meet those goals, including generator efficiency improvements, redispatch from coal to gas fueled generation

, increased reliance on renewable resources, and increased energy efficiency.
State plans will be required as early as 2016 but may be deferred until 2018 subject to collaborative approaches and regional solutions. The EPA ’s state

- specific carbon reduction goals are proposed to be effective beginning in 2020. Ba sed on its modeling and assessment of the proposed CPP, t he EPA has projected generator retirements; Figure 1 shows projected generation retirements in the Southwest Power Pool ( SPP ) region and adjacent s ystems according to EPA’s Integrated Planning Model ( IPM ) Option 1

simulation

.

Figure 1: EPA ’s Projected EGU Retirements by 2020 in the SPP Region and Adjacent Systems

1 For purposes of this assessment, SPP has included the Integrated Systems utilities, which are in the process of joining the organization.Page 2 of 7 October 8, 2014

The EPA IPM assumptions for SPP include s retirements of approximately 9,000 MW of capacity associated with existing coal and gas

- fired units currently relied upon to serve load obligations in the SPP region. EPA’s projected E lectric G enerating U nit ( EGU ) retirements represent approximately 6,000 MW of additional capacity being retired in the SPP region beyond that currently expected by 2 020. The EPA projections represent approximately a 200% increase in retired generating capacity compared to SPP’s current expectations.

Scope of Work

The scope of this reliability impact assessment ( Assessment ) reflects input from member representatives

under the guidance of SPP’s Strategic Planning Committee and other stakeholders

. This is a cursory analysis to help inform comments that are to be submitted to the EPA on the draft rule by December 1

, 2014.

This Assessment evaluate s the impacts of the EPA’s projected EGU retirements within SPP and adjacent areas on reliability of the bulk power system within the SPP region. R eliability impacts were evaluated by identifying bulk power system equipment overloads and low voltages both during system i nt act conditions and during loss of a single element (Transmission System Impact Analysis) and by determining impacts to SPP’s reserve margin (Resource Adequacy Analysis)

. SPP evaluated the impacts of the EGU retirements projected by the E PA t hat result from implementation of the carbon emission reduction goals proposed in CPP

, but due to time constraints did not evaluate t he viability or reliability impacts of any of

the building blocks used to establish those proposed goals

.

Transmissio n System Impact Analysis (TSIA)

Method

SPP staff d evelop ed power grid model s to a ssess how compliance with the proposed CPP w ould impact reliability in the SPP region . The TSIA incorporate d the retirements reflected by EPA in their IPM models based on the Option 1 State simulation for 2020.

Part 1 of the TSIA assumed the retire d capacity would be replace d by existing unused capacity remaining within the SPP footprint and surrounding areas

. Part 2 of the TSIA assumed the retired capacity would be replaced by a combination of existing unused capacity and new gas

- fired and wind resource s in the SPP footprint as needed to address capacity deficiencies. Both parts include performance of steady

state power flow analyses using models developed as described below to evaluate transmission system performance when all transmission elements are in service (“system intact”) and during conditions after which any single transmission element, including a generator, is taken out of service (“first contingency”
or “N

- 1”).

Assumption s

Part 1 of the TSIA was performed using a current 10

- year

- out summer peak model modified to reflect EPA’s projected retirements in the SPP region and surrounding areas

. R eac tive power limits on remaining generators were increased as necessary to enable a minimally solvable power flow model under system intact conditions and to account for reactive power shortfalls within SPP.

Part 2 of the TSIA was performed using an updated 10

- year

- out summer peak model modified to reflect EPA’s projected retirements in the SPP region and surrounding areas

. Additionally, n ew gas

- fired andPage 3 of 7 October 8, 2014

wind g enerato r s (see F igure 2) were added within SPP ’s region and dispatched to offset the majority of

the EPA retirements . The generators added to the model were placed in locations based on resource plans developed to support SPP’s 10

- year t ransmission p lanning evaluation

. New gas generat ors

, including combined cycle ( CC ) and combustion turbine ( CT )

, we re dispatched at approximately 5,600 MW

and new wind generators were dispatched at approximately 300 MW in SPP’s model. Wind generation

levels at existing plants in SPP were increased by approximately 3000 MW to serve load in SPP and support 2000 MW of tr ansfers from SPP to adjacent areas in Arkansas and Louisiana that would be capacity deficient based on the EPA projected retirements

. Additionally, w ind resources in MISO were increased to provide 2000 MW of transfers from MISO to these same deficient regions in Arkansas and

Louisiana

.

Figure 2: New Generation Capacity Included in Part 2 of the TSIA

TSIA Reliability Findings

Both parts of the TSIA identified significant r eliability issues

. The issues were not mitigated, but actually increased, despite the optimal generation exp ansion and conservative assumptions used in Part 2 to
address EPA retirements.Page 4 of 7 October 8, 2014

TSIA Part 1

Results from the power flow analysis performed in P art 1 of the TSIA were initially i ndeterminate under

both system intact and first contingency conditions

. As a result of the assumed EPA retir ements with no resource additions, the SPP network was so severely stressed by large reactive deficiencies that the

software used in the analysis was unable to produce meaningful results , which is generally indicative of voltage collapse and blackout conditions. In order to enable analytical results, SPP modeled increased

reactive limits at remaining generators on the system and was eventually abl e to achieve analytical results by adding approximately 5

, 2 00 MVAR of reactive production to the model during system intact conditions. Because of the arbitrary nature of artificially increasing reactive limits of generators

, reliability

indicators such a s equipment loadings and voltage levels are not accurate and are not presented in this

R eport. However, t h is analysis indicates approximately 5

, 2 00 MVAR of reactive deficiencies in the SPP footprint during system intact conditions resulting from the model ed EPA generator retirements

. Figure 3 shows the reactive power deficiencies within SPP identified by this analysis

. The most notabl e deficiencies were found in Texas and eastern Oklahoma.

Figure 3: Transmission System Impact Analysis Part 1

- Reactive Deficiencies ( MV AR )Page 5 of 7 October 8, 2014

TSIA Part 2

Part 2 of the TSIA utilized the latest optimal generation resource plan s available to SPP as well as existing wind resources to mitigate generation shortfalls within SPP. Existing wind generation in SPP and

the nor thern part of MISO were increased to serve shortfalls in the southern part of MISO. An N

- 1

assessment revealed 38 overloaded elements . These overloaded elements were identified in the portions of six states

– Arkansas, Kansas, Louisiana, Missouri, Oklaho ma, and Texas

– that operate within the SPP region. P ortions of the system in the Texas panhandle, western Kansas, and northern

Arkansas were so severely overloaded that cascading outages and voltage collapse would occur. The following graph (Figure 4 ) shows the number of overloaded elements and significance of loading expected given the EPA retirements from the proposed CPP and substantial new gas

- fired and wind generation additions:

Figure 4 : Number of Incremental Overloads in Part 2 of the TSIA

Both parts of the assessment assumed that electric transmission expansion currently planned to meet previously identified needs would be available. It is important to note that the transmission expansion currently planned in SPP does not consider EG U retirements expected as a result of the CPP.

Resource Adequacy Analysis

Resource adequacy is a fundamental requirement for a secure power system and is often measured in terms of reserve margin

. Th e A ssessment evaluated the impacts of the projected EGU retirements on SPP’s reserve margin. SPP has a minimum reserve margin requirement of 13.6 % that every SPP

member with load serving responsibilities must plan to meet with appropriate generation capacity . In evaluating th e impacts of the projected EGU retirements on SPP’s reserve margin, SPP utilized currentPage 6 of 7 October 8, 2014

load forecasts, currently planned generator retirements and additions, as well as the retirements projected by the EPA. The A ssessment showed that by 2020, SPP’s rese rve margin would fall to 4.7 %,

which is 8. 9 % below our minimum reserve margin requirement. Out of SPP’s fourteen load

- serving

members impacted by the EPA’s projected retirements

, nine would be deficient in 2020. Furthermore, SPP found that its anticipate d reserve margin would fall to

- 4.0 % in 2024 , increasing the number of

deficient load serving entities to ten

. These anticipated reserve margins represent a generation capacity deficiency of approximately 4. 6 GW in 2020 and 10 .1 GW in 2024.

Figure 5: Reserve Margin Percentage by Area

Conclusions

Development of a stable, secure, efficient and effective bulk electric power system takes time. Disruptive changes such as retirements, retrofits and/or changes in the operating characteristics of base load

resources, must be considered carefully and communicated clearly in a transparent and open process.

The f indings in this A ssessment make it very clear that new generation and transmission expansion will be necessary to maintain reliability during summer peak conditions if EPA’s projected generator

retirements occur. Even the scenario that assumes optimal resource expansion using new natural gas fired resources could be problematic during extreme winter load conditions with gas supply and de livery challenges . This A ssessment does not consider outages to accommodate retrofits/cut

- ins, time and efforts to get new replacement thermal capacity approved

, and in service to offset capacity losses or transmission upgrades to maintain system reliabil ity . More comprehensive planning efforts with stakeholders and new tools/metrics will be required. Unprecedented coordination and cooperation beyond regional planning efforts will be necessary

, but may not be timely given significant challenges with

inte rregional planning and necessary system expansion. In addition, b roader system assessments of the bulk power system, and natural gas pipeline and storage systems based on environmental constraints will be required.Page 7 of 7 October 8, 2014

Implementation of approved state plans will take time, as w i ll potential mitigation measures to address unacceptable system conditions to accommodate retirements, and/or retrofits to existing plants

, which are the major resources that drove the design of the current bulk power system. Outages to accommodate

cut

- ins of new equipment

, as well as shifts in the operating characteristics of existing base load units to more seasonal dispatch could have a profound impact on system reliability.