Subcontract Report

NREL/ SR-550-47285

March 2010

Nebraska Statewide Wind 

Integration Study: 

Executive Summary

April 2008 – January 2010

EnerNex Corporation

Knoxville, Tennessee

Ventyx

Atlanta, Georgia

Nebraska Power Association

Lincoln, Nebraska
National Renewable Energy Laboratory

1617 Cole Boulevard, Golden, Colorado 80401-3393

303-275-3000 • www.nrel.gov

NREL is a national laboratory of the U.S. Department of Energy

Office of Energy Efficiency and Renewable Energy

Operated by the Alliance for Sustainable Energy, LLC

Contract No. DE-AC36-08-GO28308

Subcontract Report

NREL/ SR-550-47285

March 2010

Nebraska Statewide Wind 

Integration Study: 

Executive Summary

April 2008 – January 2010

EnerNex Corporation 

Knoxville, Tennessee

Ventyx

Atlanta, Georgia

Nebraska Power Association

Lincoln, Nebraska

NREL Technical Monitor: Brian Parsons

Prepared under Subcontract No. AAM-9-89030-01
NOTICE

This report was prepared as an account of work sponsored by an agency of the United States government. 

Neither the United States government nor any agency thereof, nor any of their employees, makes any 

warranty, express or implied, or assumes any legal liability or responsibility for the accuracy, completeness, or 

usefulness of any information, apparatus, product, or process disclosed, or represents that its use would not 

infringe privately owned rights. Reference herein to any specific commercial product, process, or service by 

trade name, trademark, manufacturer, or otherwise does not necessarily constitute or imply its endorsement, 

recommendation, or favoring by the United States government or any agency thereof. The views and 

opinions of authors expressed herein do not necessarily state or reflect those of the United States 

government or any agency thereof.

Available electronically at http://www.osti.gov/bridge

Available for a processing fee to U.S. Department of Energy

and its contractors, in paper, from:

U.S. Department of Energy

Office of Scientific and Technical Information

P.O. Box 62

Oak Ridge, TN 37831-0062

phone: 865.576.8401

fax: 865.576.5728

email: mailto:reports@adonis.osti.gov

Available for sale to the public, in paper, from:

U.S. Department of Commerce

National Technical Information Service

5285 Port Royal Road

Springfield, VA 22161

phone: 800.553.6847

fax: 703.605.6900

email: orders@ntis.fedworld.gov

online ordering: http://www.ntis.gov/ordering.htm

This publication received minimal editorial review at NREL

Printed on paper containing at least 50% wastepaper, including 20% postconsumer waste
iii

Foreword

This work is a result of the U.S. Department of Energy’s (DOE) Wind Program and the 

National Renewable Energy Laboratory’s (NREL) interest in advancing the 

understanding of wind integration impacts in the Western Area Power Administration's 

(WAPA) service area and among consumer-owned electric power cooperatives. The 

DOE through NREL provided cost-share support to the Nebraska Power Association 

(NPA) utilities to help carry out the program objectives of this wind integration study.

NREL’s expectation was that the integration study should incorporate the best practices 

for performing such a study, including the assessment of wind’s impact in the different 

time scales (regulation, load following, and unit commitment/scheduling) using highquality wind speed and/or wind power data.

The NPA is deeply appreciative of this learning opportunity afforded by the financial and 

technical support of NREL as provided to this study. The study process and results will 

be an aid in preparing for the rapidly developing wind future of Nebraska and its 

participation in regional markets. Further, the NPA is appreciative of the dedicated and 

talented work of the consultant team of EnerNex Corporation and Ventyx, Inc. 

Representatives of NREL, the consultants, and the rest of the Technical Review 

Committee (TRC) are listed in Appendix Section 8.1. Finally, the NPA thanks all 

members of the TRC and the observers for their steady attention, cooperative efforts and 

creative thinking. The NPA does not make any representations regarding use of the 

information beyond the context presented in this report.

WAPA offers this statement: "Western appreciated the opportunity to participate in this 

study. The results and conclusions offer insight as related to potential impacts/benefits 

resulting from the integration of large quantities of wind generation. Further, Western 

concurs with the statements contained in Section 7.2.1, in that Western does not make 

any representations regarding use of the information beyond the context presented in this 

report."

The National Renewable Energy Laboratory and the Nebraska Power Association do not 

make any representations regarding use of the information in this report beyond the 

context presented in this report.
iv

Table of Contents

Executive Summary ......................................................................................................................... 1 

Introduction...................................................................................................................................... 1 

Study Background............................................................................................................................ 1 

Study Objectives.............................................................................................................................. 2 

Assumptions, Data, and Methodology............................................................................................. 4 

Wind Generation Scenarios ............................................................................................................. 4 

NPA and SPP Power System in 2018 .............................................................................................. 8 

Transmission Assumptions........................................................................................................ 8 

Methodology.................................................................................................................................. 10

Dollar Cost Basis ........................................................................................................................... 11

Costs and Implications................................................................................................................... 11

Western Nebraska Wind – Western Interconnection..................................................................... 12

Results, Findings, and Conclusions............................................................................................... 13 

Wind Generation Curtailment........................................................................................................ 14

Wind Energy Usage ....................................................................................................................... 15

Incremental Reserves..................................................................................................................... 17

Wind Capacity Value for Accreditation in SPP............................................................................. 19

Nebraska Transmission System ..................................................................................................... 22

Carbon Dioxide ....................................................................................................................... 22 

Other Considerations............................................................................................................... 23 

Total Costs (annual amounts in 2018 and assuming REC price of zero)................................ 23 

WAPA Interface for Integration .................................................................................................... 25 

Integration Costs...................................................................................................................... 25 

Wind Integration Costs – Methodology and Proxy Resource Selection ................................. 30 

Conclusions.................................................................................................................................... 31 

Closing Comments......................................................................................................................... 31 

Qualifying Statement............................................................................................................... 31 

Objectives Statement............................................................................................................... 31 

Thoughts for Future Study....................................................................................................... 31 
v

List of Figures

Figure 1: Nebraska 10% Penetration Wind Site Map..........................................................6

Figure 2: Nebraska Wind Sites Added to 10% Penetration Sites to Achieve 20% 

Penetration.............................................................................................................6

Figure 3: Nebraska Wind Sites Added to 20% Penetration Sites to Achieve 40% 

Penetration.............................................................................................................7

Figure 4: Base Case Conceptual EHV Overlay ...................................................................9

Figure 5: SPP Wind Generation Curtailment by Scenario (note: no curtailment in NPA)15

Figure 6: Nebraska Exports by Scenario ...........................................................................16

Figure 7: Monthly NPA Wind Capacity Value Estimates by Scenario.............................21

Figure 8: Monthly SPP (non-NPA) Wind Capacity Value Estimates by Scenario ...........21

Figure 9: Monthly SPP with NPA Wind Capacity Value Estimates by Penetration.........21

Figure 10: Total SPP Cost Estimates (including Nebraska) in $2018 millions – Cap & 

Trade Regulation with 117.7 M s-ton Free Allowances, REC = $0, RES(wind) = 

12.4%...................................................................................................................24

Figure 11: Change in Nebraska Generation with Incremental Reserve Requirements and 

Additional Uncertainty due to Wind Generation (“actual” case)........................26

Figure 12: SPP (including Nebraska) Normalized Wind Integration Costs (shaped proxy) 

by Scenario and Wind Year for 2018 Conditions shown both in 2018$ (top) and 

2009$ (bottom)....................................................................................................27

Figure 13: SPP (including Nebraska) Integration Costs Using Different Proxy Resources 

for 2018 Conditions shown both in 2018$ (top) and 2009$ (bottom).................29
vi

List of Tables

Table 1: Characteristics of Wind Penetration (Pen) for Study ............................................4

Table 2: Rest of SPP Wind Site Details...............................................................................5

Table 3: Wind Generation Penetration ................................................................................5

Table 4: Detailed Results for Base Scenarios – all dollars are 2018$ ...............................14

Table 5: Regulating Reserve Requirements for Study Scenarios......................................18

Table 6: Regulating Reserve Requirements for NPA as a Single Balancing Authority and 

SPP with and without NPA .................................................................................19

Table 7: Estimated Capacity Accreditation per SPP Methodology for Wind Generation 

Sites in Nebraska .................................................................................................20

Table 8: Monthly Capacity Values for Aggregated Nebraska Wind Generation Scenarios 

by Penetration......................................................................................................20

Table 9: Number of Nebraska Branches at or Near Limits ...............................................22

Table 10: Shaped and Sub-period Block Proxy Analysis at 10% and 20% Wind 

Penetration...........................................................................................................30
1

Executive Summary

Introduction

Wind generation is a source of electric energy that, in sufficient quantity, can cause 

concern for the operation of the bulk power system because of the variability and 

uncertainty of the wind. Most short-term planning and operational functions supporting 

the electric power grid are centered on supply resources that have capacity attributes – i.e. 

they can be dispatched (controlled up and down) to a specified power level for a specified 

period of time. The need to maintain very high levels of system reliability reinforces the 

preference in operations toward resources having capacity attributes. Wind generation 

usually has relatively low capacity value at system peak.

The characteristics of wind generation increase the variability of the net demand in the 

balancing area and the uncertainty about the net demand over operational planning 

horizons – e.g. next hour, next 24 hours beginning at midnight, etc. Managing a system 

with significant wind generation requires conventional resources to potentially “work a 

little harder”. Increased costs are a consequence of the additional duties performed by 

conventional generators. 

Over the past decade, many “wind integration” studies have been performed to quantify 

the operational impacts of wind generation. 

Wind generation resources in Nebraska will play an increasingly important role in the 

environmental and energy security solutions for the state and the nation. In a reference 

document entitled “Renewable Energy Background and Outlook for Nebraska Electricity 

Consumers”1

This Nebraska Statewide Wind Integration Study provides that initial study.

, the Nebraska Power Association utilities recognized the growing need for 

a specific study of wind generation in the state.

Study Background

The Nebraska Power Association (NPA) (www.nepower.org) is a voluntary organization 

that represents all segments of the Nebraska power industry: municipalities, public power 

districts, public power and irrigation districts, and cooperatives engaged in generation, 

transmission, and/or the distribution of electric energy in the nation’s only totally public 

power state. 

The organization represents approximately 28,248 GWh of annual retail load (2007 value 

– DOE) served by approximately 9,000 MW of generation capacity (including capacity 

associated with out-of-state purchases and sales). Six Nebraska utilities own and operate 

or purchase the output from a total of 152 MW-nameplate of wind generation projects in 

 1 Dated December 28, 2007, downloadable from www.nepower.org/NPA%20Report.pdf.
2

five separate locations spread across the state. During 2009, power purchase agreements

were completed for two new wind generation plants totaling 102 MW. Negotiations are 

under way to add more wind generation and still more wind additions are planned for 

later on according to the state utility integrated resource plans.

In April of 2008, NPA submitted a proposal to and received an award from the U.S. 

Department of Energy through the National Renewable Energy Laboratory for funding to 

conduct a state-wide wind integration study. 

Nebraska electric utilities, large and small, are represented directly or indirectly by their 

power supplier in this study of wind integration effects to the public power system in 

Nebraska. Qualified and interested regional and national entities were invited to 

participate as observers or as active members of the Technical Review Committee. This 

Nebraska Statewide Wind Integration Study (Study) will help Nebraska implement wind 

energy in an intelligent manner, while maintaining Nebraska's success in operating a 

reliable and economical (5th

Of significant interest to NPA was the opportunity to work directly with the U.S. DOE’s 

Wind Program, NREL, and WAPA not only because of their expertise, but also as an 

opportunity to foster regional solutions to wind integration issues. 

lowest state in 2007 at 6.28 cents per kWh) electrical system 

and achieving the diversity of a significant state-wide renewable portfolio.

Three balancing areas are fully represented: Nebraska Public Power District, Omaha 

Public Power District, and the Lincoln Electric System. Additionally all of the Nebraska 

utilities, small, medium, and large, are participating in the study through their NPA 

representation. 

Study Objectives

Objectives of the work to be done were established by NREL and supplemented by NPA.

These include evaluations of:

• The impact of wind energy on system operations using synchronized wind and 

load data and state of the art analysis techniques.

• Wind energy penetration of at least 10%, based on wind energy to total energy 

sales should be evaluated. Additional scenarios at higher penetrations are 

encouraged.

• A combination of statistical analysis and production simulation.

• The extent to which the Federal hydroelectric system can be used to help with 

cost-effective wind integration that is consistent with reliable system operation. 

• Potential mitigation approaches that may include innovative markets, institutional 

arrangements within or between Balancing Areas, or physical response on an 

economic basis.
3

Additional objectives include:

• Production of meaningful and supported results in coordination with a Technical 

Review Committee (TRC), which should include stakeholders and experts in 

wind integration analysis.

• Opportunity for Nebraska utilities to utilize the NREL/WAPA grant program to 

advance statewide wind development giving consideration not only to the 

integration impacts but also to making progress in finding relevant solutions in a 

multi-stakeholder process.

• Quantifying the expected wind integration costs using valid evaluation 

techniques, both sub-hourly and hourly and longer for Nebraska wind generation 

development.

• Involving outside experts and interested parties in order to advance team building 

for future Nebraska wind generation development and increasing the level of 

understanding among state leaders concerning wind integration issues for 

Nebraska.

• Building a database and utility expertise for ongoing improved in-house modeling 

of wind generation impacts for future studies.
4

Assumptions, Data, and Methodology

Wind Generation Scenarios

Wind generation penetration levels equivalent to 10%, 20%, and 40% of Nebraska retail 

electric energy sales in 2018 were defined as the targets for the study. 

Using a variety of criteria, individual plants were selected from the NREL Mesoscale 

database2

The “sites” selected correspond to general areas where wind generation facilities already 

exist, or where good wind resources have been identified. An attempt was made to 

include a diversity of wind resource regions in the state. It must be made clear that the 

site selection process is not intended to indicate where the best resources or potential

projects exist, but rather to develop representative scenarios for study of their impact on 

the operation of the NPA system. 

. This database was created with funding from the Department of Energy 

through NREL and consists of production profiles for wind plants east of the Rocky 

Mountains. The resolution of the profiles is in ten-minute increments for the entirety of 

historical years 2004, 2005, and 2006. The database contains profiles for 580,000 MW of 

wind generation.

Characteristics of the aggregate wind generation in the defined scenarios are given in 

Table 1 as average values for 2004-2006. The existing wind generation facilities in 

Nebraska are considered to be included in and modeled as part of these data.

Table 1: Characteristics of Wind Penetration (Pen) for Study

NPA 10% Pen 20% Pen 40% Pen

Energy (GWh) 4,523 8,855 16,831

Capacity (MW) 1,249 2,488 4,727

Capacity Factor 0.41 0.41 0.41

Average Site Size (MW) 250 311 430

Figure 1 through Figure 3 provide specific locations (close to center of each dark circle in 

the figure) of the production profiles (wind sites) selected from the NREL database for 

the 10%, 20%, and 40% penetrations.

Wind generation in areas adjacent to Nebraska can influence system operations within 

Nebraska. This is especially true with modern energy markets, where generating units are 

committed to operation and dispatched based on price signals. These signals are a 

function of load, transmission, and “stack” of available resources. With marginal costs

nearly equal to zero, wind generation is a “price taker,” which reduces locational pricing. 

If transmission capacity allows, prices are depressed across a wide region due to the 

 2 http://www.nrel.gov/wind/integrationdatasets/eastern/data.html
5

delivery of wind energy to the grid. With transmission congestion, prices may only be 

depressed on a local or sub-regional basis.

Therefore, it is important to consider the likelihood of wind development outside of 

Nebraska, so as not to skew the study results. The assumption in this study is that wind 

generation penetration in the rest of SPP would be equivalent percentage-wise with that 

in Nebraska. Table 2 provides details of the assumed wind generation in the rest of SPP 

for each scenario as average values for 2004-2006.

Table 2: Rest of SPP Wind Site Details

Rest of SPP 10% Pen 20% Pen 40% Pen

Number of Sites 7 18 33

Energy (GWH) 22,901 45,807 91,548

Capacity (MW) 6,256 12,596 25,431

CF 0.42 0.41 0.41

Average Site Size (MW) 894 700 771

SPP (including NPA) has interconnections to other regional entities, including 

MISO/MAPP and WAPA. Still other areas farther east were also modeled. To account 

for wind generation in these areas, without a dramatic increase in the scope of this study, 

the reference wind generation scenario developed for the Eastern Interconnection Wind 

Integration and Transmission Study (EWITS) was employed as the wind scenario for 

these regions. This reference case represents wind penetration that achieves current 

renewable portfolio standards. The installed capacity of wind modeled in these regions is 

around 50,000 MW, as seen in Table 3, and is a constant for each of the study scenarios. 

These represent a wind penetration outside SPP of approximately 6%. Holding external 

penetrations constant encourages more exports out of SPP for the 20% and 40% SPP 

penetration levels than if the penetrations in the external areas were increasing along with 

those inside SPP.

Table 3: Wind Generation Penetration

Name 

Plate CF

Reference 

Energy

Name 

Plate CF

Reference 

Energy

Name 

Plate CF

Reference 

Energy

NPA 1,249 41% 4,523 2,488 41% 8,855 4,727 41% 16,831

SPP w/o NPA 6,256 42% 22,901 12,596 41% 45,807 25,431 41% 91,548

PJM 25,807 36% 81,460 25,807 36% 81,460 25,807 36% 81,460

MISO/MAPP 19,547 36% 61,700 19,547 36% 61,700 19,547 36% 61,700

SERC 3,615 36% 11,410 3,615 36% 11,410 3,615 36% 11,410

TVA 1,397 36% 4,410 1,397 36% 4,410 1,397 36% 4,410

Total 57,871 37% 186,405 65,450 37% 213,642 80,524 38% 267,359

Region

10% Penetration 20% Penetration 40% Penetration
6

Figure 1: Nebraska 10% Penetration Wind Site Map

Figure 2: Nebraska Wind Sites Added to 10% Penetration Sites to Achieve 20% Penetration
7

Figure 3: Nebraska Wind Sites Added to 20% Penetration Sites to Achieve 40% Penetration 
8

NPA and SPP Power System in 2018

An Eastern Interconnection power flow case for 2018 was the starting point for 

developing the detailed model to be used in this study. The power flow case had 

previously been developed and then used for the JCSP study and was also the starting 

point for the DOE/NREL Eastern Interconnection Wind Integration and Transmission 

Study (EWITS - www.nrel.gov/wind/systemsintegration/ewits.html).

The basic model data includes generating units, the transmission network, hourly bus 

loads, and wind generation profiles as described above. Completing the model from this 

relatively straightforward foundation requires many additional assumptions. These are 

detailed in the report.

NPA loads in the model were adjusted to match monthly peak demand and energy 

projected for 2018. Care was taken to retain the shape and pattern characteristics from 

historical years 2004 to 2006 to preserve correlation to the wind profile data for those 

same historical years.

Generating unit data in the base model was also audited and updated based on inputs 

from NPA members. 

Finally, because NPA utilities became participants in the SPP market at the onset of this 

study, the modeling was structured to reflect this operational reality (the SPP day-ahead 

and ancillary services markets modeled are not in place today but are expected to operate 

in 2018). In the simulations described later, NPA generating units were committed and 

dispatched along with all other units in the SPP operating area. Hourly transactions of 

energy, both within the SPP market footprint and with external areas such as MISO, 

SERC, and TVA, were made on an economic basis. A “hurdle rate” between regions of 

$5/MWh was included in the interchange decision to reflect additional costs that needed 

to be overcome for interchange to take place between buyer and seller. Unit shares, 

whether ownership or participation transactions, were modeled for Nebraska purchases 

from out-of-state units and for Nebraska sales to out-of-state utilities.

Transmission Assumptions

The base model for the study contains a detailed representation of the transmission 

system, representing explicitly all buses at or above 115 kV. Planned transmission 

additions through at least 2013 are part of the power flow case from which the study 

model was derived. However, for the higher wind penetrations considered in the study, it 

was thought that transmission capacity could be an important issue and potentially lead to 

significant curtailment of wind generation without an adequate transmission build out.

The 10% wind penetration case (Scenario 1) was run with existing and currently 

planned/committed transmission facilities, as was an initial case at 20% penetration in 

NPA and the rest of SPP (Scenario 2). In addition, some localized transmission 

constraints were removed from the model without actually identifying specific 
9

transmission facilities necessary in operation to do so. A third case, (Scenario 3) again at 

20% wind generation penetration, incorporated a substantial regional transmission 

expansion that has been under study at SPP for some time. With the addition of NPA 

utilities to SPP, the 765-kV EHV overlay that constitutes the core of this plan was 

modified to loop through Nebraska as seen in Figure 4 below.

The EHV overlay was also initially used for the 40% wind penetration case (Scenario 4).

Figure 4: Base Case Conceptual EHV Overlay 
10

Methodology

Wind generation impacts on power systems operations are assessed through chronological 

production simulations. This is the preferred method for analyzing wind integration 

impacts, and has been used in nearly all of the major integration studies to date. 

In the simulations, units are committed and dispatched to serve loads at each bus while 

honoring transmission constraints and recognizing the security needs of the system, while 

simultaneously adjusting generation to accommodate the delivery of wind energy to the 

system. Three full years with unique 8760 hour load and wind profile data representing the 

study year of 2018 are simulated. A nodal model is employed, where all transmission in the 

study area is represented explicitly, along with all generating units and loads at bulk 

delivery points.

With annual production simulations as the basic tool, a large number of cases are run to 

determine how increasing amounts of wind generation affect the utilization of other 

generating resources and the transmission system, consumption of fuel, and market prices 

for electric energy. In addition to analysis of the four base scenarios, a significant number 

of additional production simulation cases were run to explore how key variables or 

assumptions would affect the results. 

A key goal of a wind integration study is to determine integration costs associated with 

wind generation. The additional variability and uncertainty attributable to wind generation 

increase the requirement for regulating reserves in real-time operations (above that already 

required for regulating load), and also introduce some additional inefficiency in the dayahead energy market due to increased errors in the aggregate forecast of load and wind 

generation. These general effects of wind generation are captured in the production 

simulations by a) optimizing the deployment of generating units (i.e. unit commitment) to 

forecasts of hourly wind and load for the next day rather than the “actual” quantities per the 

profiles mentioned above; and b) increasing the hourly reserve constraint (or requirement)

consistent with the amount of wind generation during the hour. Additionally the shape or 

variability of the wind can be considered as an integration cost.

Integration costs are driven by changes in the use of the thermal generation fleet in 

response to the wind. Typically, the “actual” wind case simulation (including the effects 

of forecast error, incremental reserves and wind variability) will result in higher 

production costs than the “ideal” wind case (no forecast error, incremental wind reserves 

or wind variability). Given the makeup of Nebraska’s thermal generation fleet, increased 

reserve requirements typically cause coal units to back down to carry reserves. This

results in higher cost resources, particularly combined cycle units, being brought on to 

serve the energy previously generated by the coal units. These higher cost resources also 

respond to the faster ramps and forecast errors associated with wind. 

The intent of these simulations is to mimic, as closely as possible, the assumed 

operational structure for SPP in the study year. It is assumed that the SPP energy markets 
11

in 2018 will consist of day-ahead and real-time (or sub-hourly) energy markets as well as 

an ancillary services market. All of these markets are not operational in SPP today.

Simulation outputs include the hourly operational profile of each generating unit in the 

model and hourly flows on all transmission lines in the model. Locational marginal 

prices (LMPs) and production costs are also key metrics.

Dollar Cost Basis

Throughout the report, dollars are given in 2018 nominal values unless otherwise noted.

Current cost numbers were escalated to 2018 using various rates depending on the 

particular cost element. Representation of results in 2018 nominal dollar terms is a 

common utility procedure and provides for the resulting (estimated) future relationship 

between such cost elements. However, for the purposes of potential comparison to other 

studies, normalized wind integration cost results are presented in 2009 dollar terms by deescalating the 2018 results to 2009 at 2.5% per year. Additionally, the cost value given in 

the Western Nebraska Wind – Western Interconnection is presented on a 2008 dollar basis.

Costs and Implications

A simplified methodology was developed to facilitate calculation of the total costs 

associated with each of the scenarios studied, as well as certain sensitivity cases. 

Because of the necessary simplifications, the total costs are useful as a relative metric to 

compare the cases. They do not represent a full accounting of all the details associated 

with each of the scenarios, and are very dependent on the assumptions established for this 

study. 

The cost estimation procedure considers all of SPP including Nebraska, because of the 

shared-reserve modeling, and can be thought of in a step-wise manner as follows:

• A reference 2018 total cost is estimated with no CO2 regulation (cost) or federal 

Renewable Energy Standard or significant REC pricing.

• An incremental wind purchase cost is estimated for the increment of wind 

generation that is added above the existing amount now installed in the SPP.

• An incremental transmission cost is estimated for the increment of transmission 

line and substation facilities that will be needed as wind generation is added. 

• A cost of CO2 emissions is included at various levels depending on the scenario 

description. The cap-and-trade estimates are patterned after the proposed 

Waxman-Markey bill. Alternative total cost results are presented for both capand-trade and tax regulation scenarios.

Essentially, the total cost estimate for a case then becomes:

• the reference cost 

• plus incremental wind cost
12

• plus incremental transmission cost

• minus the delta on PROMOD adjusted production cost (to convert from tax to 

cap-and-trade, if done for that case).

The list of assumptions used in these calculations is detailed in the report. Implications 

of this costing analysis are listed in the “Results, Findings, and Conclusions” section of 

this Executive Summary. 

Western Nebraska Wind – Western Interconnection

The western-most area of the state of Nebraska is part of the Western Interconnection in the 

U.S.; the remainder of the state operates as part of the Eastern Interconnection. This artifact 

of history and the distribution of population across the lower 48 states has the effect of 

dramatically limiting the transfer of electric energy from eastern Nebraska to western 

Nebraska. There are several connections between the grids via back-to-back AC-DC-AC 

ties. Two of these connections are located in Nebraska. Transfer capability over these ties, 

however, is quite limited.

Western Nebraska is a very low load area, meaning that large amounts of wind 

generation will require transmission capability to “export” power out of the area to load 

centers. There is limited transmission capability, either to the east or to the west, due to

commitments already in place for other resources. Consequently, it was impractical to 

incorporate those areas operating in the Western Interconnection (and their potential wind 

generation) directly into the analysis. 

Given that the likely load center for wind in far western Nebraska would actually be in 

the Western Interconnection, a separate transmission evaluation was conducted to assess 

challenges for development of wind generation in this portion of the state. 

In collaboration with the WAPA Rocky Mountain Region, the following topics pertaining 

to wind in the western portion of Nebraska in the Western Interconnection were 

addressed:

• Identification of how much wind generation could be injected into the western 

Nebraska transmission system without requiring transmission system upgrades.

• Determination of the transmission system upgrades required to add 300 MW of 

wind generation in western Nebraska in the Western Interconnection.
13

The focus for this part of the study was also nearer-term than the larger analytical effort, 

and looked at the 2012 time frame before considering 2018.

The analysis determined that the existing transmission network could connect and 

provide delivery for about 50 MW of wind generation. Approximately $16 million 

(2008$) in transmission improvements would be necessary to interconnect 300 MW.

In the 2018 time frame, additional transmission improvements would also be required to 

connect 300 MW of wind generation, although the details of the necessary upgrades 

differ from what was determined for the earlier year. 

Wind integration costs, as computed for the eastern regions of the state and for the SPP 

market footprint, were not addressed in this component of the complete study. 

Results, Findings, and Conclusions

Some details of the production simulations for the base scenarios are found in Table 4. 

The large volume of numerical results precludes a substantive discussion in this 

Executive Summary of the production simulation cases run and analyzed as part of this 

study effort. In this section, a review of the key study findings and conclusions, along 

with supporting tables, charts, and graphs from the body of the report is provided.

For brevity in referencing, four scenarios are numbered:

• Scenario 1: 10% wind penetration in Nebraska (Figure 1) and the rest of SPP 

without the addition of an EHV transmission overlay.

• Scenario 2: 20% wind penetration in Nebraska (Figure 1 and Figure 2) and the 

rest of SPP without the addition of an EHV transmission overlay.

• Scenario 3: 20% wind penetration in Nebraska (Figure 1 and Figure 2) and the 

rest of SPP with the addition of a 765-kV transmission overlay.

• Scenario 4: 40% wind penetration in Nebraska (Figure 1, Figure 2, and Figure 3) 

and the rest of SPP with the addition of a 765-kV transmission overlay.

Within each of the scenarios, the wind and load patterns for all three historical years 

(2004, 2005, and 2006) were also modeled as separate cases. Further, localized 

transmission additions necessary to handle the wind generation injections were not 

specifically identified but were implicitly assumed to be present as described in the 

Transmission Assumptions section.
14

Table 4: Detailed Results for Base Scenarios – all dollars are 2018$

Notes on Base Scenario Results:

• Reserves noted as "wind reserves" are the incremental regulating reserves associated with the additions of wind 

generation.

• APC = Adjusted Production Cost

• SPP includes NPA unless otherwise noted

• Scenario 1: 10% Wind Penetration

• Scenario 2: 20% Wind Penetration

• Scenario 3: 20% Wind Penetration w EHV Overlay

• Scenario 4: 40% Wind Penetration w EHV Overlay

• Integration costs are based on shaped proxy resource.

2004 2005 2006 2004 2005 2006 2004 2005 2006 2004 2005 2006

Load (TWh) - SPP 265 265 265 265 265 265 265 265 265 265 265 265

Actual Wind (TWh) - SPP 25.75 27.76 27.52 49.69 51.63 52.95 52.39 54.79 56.32 100.31 104.20 107.23

Ideal Wind (TWh) - SPP 25.68 27.15 27.45 49.61 51.51 52.86 52.38 54.78 56.31 100.27 104.14 107.18

All Other Gen/Resources (TWh) - SPP 250.72 249.41 250.05 237.34 236.55 236.09 237.17 236.29 235.83 214.41 212.45 211.00

Actual APC ($M) - SPP 14,815 14,685 14,655 13,162 13,013 12,924 12,772 12,579 12,462 9,759 9,488 9,334

Ideal APC ($M) - SPP 14,770 14,639 14,607 13,079 12,922 12,828 12,683 12,480 12,355 9,542 9,283 9,101

Delta APC (Actual minus Ideal) - SPP 45 45 48 82 90 96 89 100 107 217 204 233

Integration Costs ($/MWh) - SPP 1.75 1.66 1.74 1.65 1.75 1.81 1.70 1.82 1.90 2.16 1.96 2.18

Wind Curtailment (%) - Nebraska 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0%

Wind Curtailment (%) - Rest of SPP 2% 2% 3% 6% 7% 7% 0% 0% 0% 5% 5% 5%

Exports (TWh) 11.48 12.24 12.59 21.24 22.40 23.09 24.53 26.09 27.13 49.69 51.37 52.85

CO2 Emissions (Million Short Tons) 203.07 202.83 202.75 193.22 192.93 192.46 194.53 194.22 193.59 175.64 174.14 172.58

SPP Wind Reserve (Max MW) 884 853 852 1,538 1,540 1,542 1,538 1,540 1,542 3,003 3,041 3,034

SPP Wind Reserve (Avg MW) 513 505 499 1,021 1,007 996 1,021 1,007 996 2,094 2,058 2,042

Scenario 1 Scenario 2 Scenario 3 Scenario 4
14

Wind Generation Curtailment

Assuming certain localized transmission line additions are made and Knoll-Axtell 345-

kV line is built, there was no significant wind generation curtailment in Nebraska in any 

case with or without the overlay. That is, all scheduled wind generation was 

accommodated by re-dispatching other generation and exporting excess wind energy, all 

within modeled transmission limits. As described in the Transmission Assumptions 

section, lines nearby to the wind injection points were allowed to overload for study 

simplicity rather than determine all the specific additions needed. Further the 40% case 

was only run with the overlay in place.

There was also no significant violation of Nebraska thermal unit minimums (i.e. dump 

energy) in any of the cases.

• With the wind dispatch price of -$40/MWh (assuming $15/MWh Renewable 

Energy Credit, REC and $25MWh Production Tax Credit, PTC) wind has priority 

over other resources, i.e., other resources re-dispatch or even curtail before wind 

does.

• Access to large export markets was a key factor in accommodating the wind 

generation additions.

Although 20 major flow gates were monitored in Nebraska, it’s possible that some local 

congestion was not captured in the analysis which could lead to curtailment.

In the rest of SPP for the base cases, wind curtailment was found to be:

• 2% at the 10% penetration without the overlay.

• 7% at the 20% penetration without the overlay.

• 0% at the 20% penetration with the overlay.

• 5% at the 40% penetration with the overlay.
15

These results are summarized in Figure 5.

Figure 5: SPP Wind Generation Curtailment by Scenario (note: no curtailment in NPA)

Wind Energy Usage

Consistently as wind penetration increased, the study results indicate SPP (including 

Nebraska) increasing exports by approximately half of the amount of the wind generation 

increases. Specifically, for Nebraska only:

• Increasing 10% wind penetration to 20% wind penetration, Nebraska wind energy 

increases by 4.35 TWh and exports increase by 3.20 TWh (74%) when using the 

averages of the 3 wind years in the base cases of Scenarios 1 and 2, see Figure 6.

• Increasing 20% wind penetration to 40% wind penetration (with the EHV 

overlay), Nebraska wind energy increases by 8.12 TWh and exports increase by 

4.74 TWh (58%) when using the averages of 3 wind years in the base cases of 

Scenarios 3 and 4, see Figure 6.

'Rest of SPP' Wind Curtailment in Percent

0.00%

1.00%

2.00%

3.00%

4.00%

5.00%

6.00%

7.00%

8.00%

Scenario 1 Scenario 2 Scenario 3 Scenario 4

% Wind Curtailment

2004

2005

2006
16

Although it is impossible to determine the source of energy exported, the increased wind 

penetrations in Nebraska / SPP correspond to increased energy exports. Note that in areas 

external to SPP, the wind penetrations were held constant at a weighted 6% level across 

all of the SPP variations in penetration. As such, the external system had greater 

flexibility at the higher penetration scenarios to accept imports of wind than if it had the 

same higher penetrations as in SPP/NPA.

Figure 6: Nebraska Exports by Scenario

Nebraska Exports by Scenario

-

5,000.00

10,000.00

15,000.00

20,000.00

25,000.00

Scenario 1 Scenario 2 Scenario 3 Scenario 4

GWh

2004

2005

2006
17

Incremental Reserves

Wind generation has a substantial impact on the requirements for regulating reserves (an 

amount of spinning reserve responsive to Automatic Generation Control (AGC) that is 

sufficient to provide normal regulating margin) relative to what the load by itself

requires. For the SPP market, 10% wind energy in NPA and SPP will increase the 

average hourly requirement by around 500 MW. At 20%, the incremental amount is 

about 1000 MW, and rises to about an additional 2000 MW at 40% penetration, all are 

relatively linear.

There are costs associated with carrying these additional spinning reserves, which have 

been captured in the production simulations. It should also be noted that the incremental 

hourly amounts are small when wind generation is low and, obviously the largest at high 

levels of wind production. Under these conditions, however, conventional generation will 

be “unloaded” and freed up to contribute to the reserve needs.

The calculation of the increased regulating reserve requirement was done outside of, and

prior to, the production simulations. The additional amounts of reserves are estimated by 

employing some statistical and mathematical analysis of higher resolution (10-minute 

intervals or less) wind and load data.

Results of these computations for the base scenarios are shown in. Because the 

requirements vary hourly with both wind and load, the average and maximum values for 

each year of the wind and load profile data are shown. At 10% wind penetration in SPP, 

including NPA, the average value of the hourly regulating reserve more than doubled. At 

40% wind penetration, regulating reserves requirements increase by over 7 times.
18

Table 5: Regulating Reserve Requirements for Study Scenarios

Wind 

Nameplate

Max Average Max Average Max* Average MW

2004 profile 533 301 1142 814 884 513 7,505

2005 profile 526 301 1146 806 853 505 7,505

2006 profile 528 295 1152 794 852 499 7,505

20% Penetration

2004 profile 533 301 1796 1322 1538 1021 15,084

2005 profile 526 301 1802 1308 1540 1007 15,084

2006 profile 528 295 1800 1291 1542 996 15,084

40% Penetration

2004 profile 533 301 3261 2395 3003 2094 30,158

2005 profile 526 301 3261 2359 3041 2058 30,158

2006 profile 528 295 3257 2337 3034 2042 30,158 *

Delta Max colum represents the coincidental maximum delta of Load Only and Load and Wind

SPP with Nebraska

 10% Penetraton

Load Only Load and Wind

Delta Load and 

Wind - Load

The increase in regulating reserves to manage the additional variability and short-term 

uncertainty attributable to wind generation is one of the major operating impacts. There 

are costs associated with the increased requirement and potential control performance 

degradation if adequate reserve capacity cannot be found among units in the operating 

area. Both of these issues are evaluated directly in the production simulations. 

Table 6 illustrates one of the benefits of larger operating areas for managing wind 

generation. If NPA were operated as a single balancing area, not part of the SPP market, 

it would be responsible for providing regulating reserves for the wind generation in 

Nebraska. For the 10% case, the average hourly regulating reserve requirement for load 

and wind in the NPA balancing area on its own would be around 150 MW. This is in 

contrast with a 750 MW requirement for the rest of the SPP market footprint. The value 

of aggregation can be clearly seen by comparing the SPP requirements from the two 

tables. Adding Nebraska – and its wind generation for the 10% case – to the SPP 

operating area (and ancillary services market) increases the regulating requirement by 

about 50 MW (to 794 MW). This is less than the sum of the requirement for SPP and 

Nebraska operating separately (742 MW + 148 MW = 890 MW). With more wind 

generation, the aggregation effect is even more pronounced. 
19

Table 6: Regulating Reserve Requirements for NPA as a Single Balancing Authority and 

SPP with and without NPA

Wind 

Nameplate

Max Average Max Average Max* Average MW

SPP with Nebraska 528 295 1152 794 852 499 7,505

SPP w/o Nebraska: A 460 256 1111 742 821 486 6,256

Nebraska alone: B 75 45 216 148 177 118 1,249

Total A + B 535 301 1327 890 998 604 7,505 *

Delta Max Column represents the coincidental maximum delta of Load Only and Load and Wind

Delta Load and 

10% Penetration Wind - Load

2006 profile

Load Only Load and Wind

Wind Capacity Value for Accreditation in SPP

The SPP criteria for calculating monthly capacity value were used for these findings,

because that is the criteria now applicable to Nebraska utilities. They are not based on an 

Effective Load Carrying Capacity methodology as are many criteria. Three years of 

Nebraska hourly wind data were correlated with corresponding 3 years of Nebraska hourly 

load.

The monthly capacity value for individual wind sites studied in Nebraska ranged from a 

0.06% minimum to a 16.5% maximum, Table 7. It is noteworthy that the two most 

common months in which Nebraska has its annual peak (July and August) are 

unfortunately the same two months in which the capacity values are the lowest.

When all the Nebraska wind sites were aggregated, the lowest monthly capacity values 

were observed in the summer months of June, July, and August, while the highest values 

were observed in April, May, September, and October, as shown for 40% penetration in

Table 8 and in Figure 7. The aggregated minimum increased to 6.55% while the maximum 

remained at 16.5%, Table 8, 40%.

For SPP (without Nebraska) the monthly capacity values for individual wind sites ranged in 

value from a 0.03% minimum to a maximum of 16.55%. The lowest values were observed 

in December and January. 

When the SPP (without Nebraska) wind sites were aggregated, the monthly capacity value 

minimum and maximum increased to 4.99% and 22.4% respectively, as shown in Figure 8.

Aggregating all wind sites of Nebraska and SPP improved the monthly capacity values by 

increasing the minimum to 10.79% and maximum to 30.35%, as shown in Figure 9. This 

demonstrates the benefit of diversity across broader regions with increased wind capacity, 

assuming sufficient transmission exists. Although the data for November in these two 

figures stands out as atypical, nothing could be found in the NREL data that was obviously 

inappropriate.
20

It is noted however, that the SPP accreditation criteria is currently applied to individual 

wind units only, rather than to an aggregation of plants.

Methods of calculating capacity credit for wind vary across the country and produce 

different results. A standardized method of calculating the capacity credit of wind is 

under investigation by FERC. 

Table 7: Estimated Capacity Accreditation per SPP Methodology for Wind Generation Sites 

in Nebraska

Nameplate 261 268 240 235 245 285 453 501 1100 479 660

Site ID 22 143 160 205 208 47 245 1149 70 76 695

Jan 2.79% 1.19% 1.82% 2.24% 3.59% 2.66% 2.81% 2.25% 1.63% 2.30% 4.49%

Feb 6.60% 2.79% 4.23% 4.06% 10.85% 6.26% 2.52% 10.16% 4.36% 4.77% 6.45%

Mar 5.27% 2.22% 2.98% 4.24% 3.90% 4.64% 4.01% 2.95% 3.79% 3.57% 4.95%

Apr 6.46% 8.25% 8.42% 4.69% 3.04% 5.46% 6.38% 0.86% 8.12% 8.73% 3.08%

May 13.52% 8.35% 5.35% 9.26% 16.53% 12.09% 4.55% 14.57% 11.77% 4.11% 4.39%

Jun 4.45% 1.86% 1.98% 0.63% 6.22% 5.41% 2.80% 8.19% 1.58% 2.11% 3.22%

Jul 1.54% 1.17% 1.08% 0.06% 1.96% 0.54% 0.39% 1.26% 1.37% 1.51% 2.41%

Aug 3.07% 0.81% 2.22% 0.34% 1.94% 3.29% 1.39% 4.11% 1.19% 1.86% 3.35%

Sep 10.40% 6.79% 4.05% 5.35% 12.66% 10.19% 3.14% 12.53% 9.25% 4.02% 3.13%

Oct 7.92% 10.23% 1.47% 5.21% 8.36% 7.35% 2.32% 5.47% 10.23% 1.63% 5.37%

Nov 2.10% 0.86% 2.43% 1.20% 0.98% 1.64% 5.57% 0.53% 1.77% 4.33% 6.23%

Dec 3.94% 3.59% 3.76% 3.87% 2.73% 4.07% 4.34% 1.74% 3.55% 2.80% 3.31%

NPA - 10% Wind Sites NPA 20% Wind Sites NPA 40% Wind Sites

Table 8: Monthly Capacity Values for Aggregated Nebraska Wind Generation Scenarios by 

Penetration

10% 20% 40%

Nameplate 1249 2488 4727

Jan 6.18% 7.96% 9.02%

Feb 7.73% 10.30% 12.74%

Mar 7.29% 7.71% 11.18%

Apr 11.19% 14.29% 15.65%

May 13.41% 16.39% 16.56%

Jun 7.75% 9.34% 8.91%

Jul 2.94% 4.75% 6.55%

Aug 4.98% 8.83% 7.56%

Sep 10.61% 11.20% 13.78%

Oct 8.60% 11.34% 13.05%

Nov 5.52% 7.19% 10.50%

Dec 5.80% 7.05% 10.23%

All Nebraska Sites
21

Figure 7: Monthly NPA Wind Capacity Value Estimates by Scenario

Figure 8: Monthly SPP (non-NPA) Wind Capacity Value Estimates by Scenario

Figure 9: Monthly SPP with NPA Wind Capacity Value Estimates by Penetration
22

Nebraska Transmission System

New transmission will be required to bring any significant new wind resources online. 

The transmission system will be stressed with increased wind penetration. The 

transmission system expansion must be designed with wind expansion in mind to

minimize those stresses.

• Twenty flow gates involving Nebraska were modeled and fifteen of them were 

constrained somewhat. They range from one hour to 4,970 hours out of the year 

depending on the scenario and flow gate. Nine flow gates had no constrained 

hours.

• Table 9 shows the number of non-monitored branches (not flow gates) in 

Nebraska that approached or exceeded their thermal limits by scenario using the 

2006 wind/load patterns. In the model, these branches are 115-kV to 345-kV 

lines that are allowed to exceed limits in recognition that other transmission will 

need to be designed and installed to relieve these overloads.

• Specifically, the transmission system shows increased usage and risk of overloads 

as wind penetration increases, but those overloads decrease with the addition of 

transmission designed to deliver the wind energy (i.e., the 765-kV overlay), as 

shown in Table 9. That is, in all four scenarios, overloads exceed limits as

penetration increases without adding transmission. Conversely from Scenario 2 

to Scenario 3, the numbers decrease with the addition of the overlay.

Table 9: Number of Nebraska Branches at or Near Limits

Carbon Dioxide

Increased wind penetrations result in lower CO2 emissions, as shown in Table 4. 

• Nebraska CO2 emissions decrease by about 8% between the 10% wind case and 

the 40% wind case (using averages of 3 wind years).

• The rest of SPP decreases CO2 emissions by about 15% between the same cases 

(using averages of 3 wind years).

• Increased exports due to wind will offset emissions outside of SPP.

Scenario 1 Scenario 2 Scenario 3 Scenario 4

Violations of Thermal Limit 6 15 10 23

Over 90% of Thermal Limit (excludes 

violations) 6 11 4 2

Over 80% of Thermal Limit (excludes 

violations and 90% violations) 15 15 11 10

Total Non-monitored Branches over 

80% of Thermal Limit 27 41 25 35
23

A pure price penalty on CO2 is not very effective at reducing CO2 emissions in SPP, 

including Nebraska, (given the consistent expansion fleet modeled for all penetration 

levels) until the penalty gets very large (using 2006, Scenario 3 and its variations).

• A $25 / short ton penalty reduced SPP CO2 emissions by about 2% from the no 

penalty case.

• A $50 / short ton penalty reduced SPP CO2 emissions by about 6% from the no 

penalty case.

• A $120 / short ton penalty reduced SPP CO2 emission by about 19% from the no 

penalty case.

Increased price penalties on CO2 result in decreased wind integration costs as more gas 

resources are committed due to CO2 penalties in both the ideal and actual cases that 

diminish the cost difference between coal and gas.

Significant carbon reductions through dispatch penalties or emissions caps result in huge 

increases in the use of natural gas for electricity. Combined cycle use in Nebraska 

increases by 138% in the CO2 reduction case ($120/short ton) when compared to the base 

case ($25/short ton), increasing CC capacity factors to over 80%.

Other Considerations

There would be some additional costs associated with managing wind generation not 

captured in these production simulations:

• Additional maintenance and forced outages and de-rates

• Degradation of heat rate from ramping, cycling, and range of operation

• Increase in emission rate per MWh production due to increased ramping that is 

not fully embodied in historical data that is used to determine modeled emission 

rates

• Other potential factors

Production simulation results could be used to make estimates for some of these factors, 

but that was not attempted in this study.

Total Costs (annual amounts in 2018 and assuming REC price of zero)

In most cases, two incentives for wind generation are being modeled: a production tax 

credit (PTC) and a carbon dioxide emission price. It is not likely that three incentives 

will exist in 2018. Though it is acknowledged that the PTC extends through 2012, but it 

is not certain that it would remain in 2018 after a federal Renewable Energy Standard is 

adopted.

The primary results of the total cost estimation process for SPP including Nebraska are 

shown in Figure 10. It illustrates four cost categories, in both bar chart and tabular form, 

for fifteen primary cases run on the 2006 wind and load patterns: incremental wind 
24

generation cost (cost above existing wind), incremental transmission, CO2 prices, and 

other costs (production and other fixed costs). For this set of cases, the total cost 

estimates for 2018 range from $23.7 billion to $28.5 billion, a 20% increase over the 

reference case to the CO2 reduction case identified as $50/short ton ($120 in the 

dispatch). If the CO2 regulation is a tax instead, the corresponding case is accordingly 

higher in cost.

Figure 10: Total SPP Cost Estimates (including Nebraska) in $2018 millions – Cap & Trade 

Regulation with 117.7 M s-ton Free Allowances, REC = $0, RES(wind) = 12.4%

The following observations and conclusions assume a Renewable Energy Credit (REC) 

price of $0:

• $25/short ton CO2 price for cap-and-trade adds approximately 9% (or $2.2 

billion) to the total cost reference, which is estimated at $23.7 billion for existing 

wind and no CO2 cost in 2018. Under a tax regulation, that increase becomes 

approximately 22%.

• Each 10% penetration (7,540 MW) adds approximately 1.7% to the total cost 

reference cost when the CO2 cap-and-trade price is $25/short ton (comparing 

10% and 40% bases). 
25

• Each 1% increase in revenue requirement equates to about $237 million per year.

• Only the CO2 reduction case (‘120/50’) has emissions that approach the cap by 

substituting gas for coal generation. 

• At the 10% penetration level, operating Nebraska as a stand-alone market (rather 

than as a part of the SPP market) raises the SPP-wide cost (including Nebraska) 

by $22 million annually for either CO2 regulation with price at $25/short ton; 

however, this is not considered to be a comprehensive market analysis.

• Under cap-and-trade, there is a bigger jump in cost (9.5%) from $0 to $25/ton 

than from $25 to $50/ton (6.0%). This is likely due to the loss of 13.5 TWh 

exports in going from $0 to $25/ton.

• Assuming the same case dispatches for the 20% penetration case, and the same 

CO2 prices, the total costs for SPP under a tax regulation for CO2 (rather than 

cap-and-trade), are approximately $3 billion higher at $25/short ton tax for CO2 

emissions and $6 billion higher at $50/short ton tax.

WAPA Interface for Integration

Scheduling WAPA firm power to Nebraska utilities proportional to load-net-wind vs. 

proportional-to-load may save Nebraska $1 million, subject to Missouri River Basin 

management priorities.

Integration Costs

Wind Integration Costs – Results

Wind integration costs are production cost increases due to wind forecast error, wind 

regulating reserves and wind shape variability. The costs are typically normalized to wind 

energy by dividing production cost delta by total wind energy (see Methodology section 

for more background).

Costs to integrate wind increase with wind energy penetrations because more natural gas 

fired resources are used to respond to wind forecast error while the displacement of coal 

energy backed down for reserves. This is shown in Figure 11. SPP integration costs 

increase from an average of $46 million at 10% wind to an average of $218 million at 

40% wind penetration using the shaped proxy.

Normalized Integration Costs (as initially defined with shaped proxy3

Figure 12

resource) are 

relatively small and in a narrow range of $1.65 - $2.18/MWh in 2018$ (or $1.32 -

$1.75/MWh in 2009$) for the multiple penetration levels and years modeled for the base 

case, as shown in . 

The base penetration scenarios show a consistent increase in use of gas fired resources 

(especially combined cycle plants) to deal with wind forecast error and increased (and

 3 Shaped Proxy - a proxy wind resource that uses the actual delivered shape of the wind but is perfectly known (no forecast error) and requires 

no additional regulating reserves.
26

variable) reserve requirements when comparing actual wind to ideal wind runs. In 

accommodating wind reserves and forecast error, the Nebraska combined cycle usage 

increases by 18%, when comparing the actual case to the ideal case at 40% wind 

penetration. 

The initial definition of integration costs (with shaped proxy) is only capturing effects of 

incremental reserves for wind and wind forecast error and is not capturing shape 

variability costs.

Figure 11: Change in Nebraska Generation with Incremental Reserve Requirements and 

Additional Uncertainty due to Wind Generation (“actual” case)
27

Figure 12: SPP (including Nebraska) Normalized Wind Integration Costs (shaped proxy) by 

Scenario and Wind Year for 2018 Conditions shown both in 2018$ (top) and 2009$ (bottom)

SPP Integration Costs Normalized to Wind Energy

(2018$)

-

0.50

1.00

1.50

2.00

2.50

Scenario 1 Scenario 2 Scenario 3 Scenario 4

$/MWh - (2018$)

2004

2005

2006

SPP Integration Costs Normalized to Wind Energy 

(2009$)

-

0.20

0.40

0.60

0.80

1.00

1.20

1.40

1.60

1.80

2.00

Scenario 1 Scenario 2 Scenario 3 Scenario 4

$/MWh (2009$)

2004

2005

2006
28

Other proxy resources were tested to help measure effects of hour-to-hour wind 

variability on the generation fleet. Sensitivity cases show that a moving average or block 

(sub-period or flat) for proxy captures more integration costs, referred to as shape or 

variability costs, see Figure 134

• Proxy resource sensitivity results show $4.01/MWh (or $3.21/MWh in 2009$) for 

10% penetration with daily block proxy and $2.40/MWh (or $1.92/MWh in 

2009$) for a sub-period block proxy. 

.

• At 20% wind penetration, those integration cost results increase to $5.36/MWh 

(or $4.29/MWh in 2009$) for the daily block proxy and $3.88/MWh ($3.11/MWh 

in 2009$) with the sub-period block proxy.

• Non-normalized integration costs using the daily block proxy for SPP are $110 

million at 10% wind and $66 million using the sub-period block proxy; these 

values increase to $286 million and $206 million respectively for 20% wind 

penetration.

• These increasing differentials for alternative proxies as wind penetration increases 

may indicate that integration costs associated with wind variability are increasing 

with the amount of wind although the other costs (reserves and uncertainty as 

measured with the shaped proxy) are remaining relatively flat as wind penetration 

increases.

• Analysis indicates that the modeled system outside of SPP is absorbing some of 

the costs of wind variability represented in the block proxies (daily and subperiod) and that total SPP integration costs could be as high as $5.41/MWh 

(2009$) at 10% wind penetration and $9.26/MWh (2009$) at 20% wind 

penetration when considering those exported costs (using the sub-period block 

proxy), Table 10.

 4

Flat block proxy consists of a 24-hour constant block of energy equal to the amount of energy of the actual wind profile for the same day.

Sub period block proxy distributes the daily energy during on peak and off peak hours

Moving average proxy is a profile that represents a periodic hourly average of energy, (5 and 13 hour averages were used)

.
29

Figure 13: SPP (including Nebraska) Integration Costs Using Different Proxy Resources

for 2018 Conditions shown both in 2018$ (top) and 2009$ (bottom)

SPP Integration Costs PROXY Resource Comparison

(2018$)

4.01

2.40

2.78

1.67 1.74

5.36

3.88 3.73

2.15

1.81

-

1.00

2.00

3.00

4.00

5.00

6.00

Daily Block Proxy Subperiod Block

Proxy

13 HR MA Proxy 5 HR MA Proxy Shaped Proxy

$/MWh - (2018$)

10% Wind

20% Wind

(no EHV

Overlay)

SPP Integration Costs PROXY Resource Comparison

(2009$)

3.21

1.92

2.23

1.34 1.39

4.29

3.11 2.98

1.72

1.45

-

0.50

1.00

1.50

2.00

2.50

3.00

3.50

4.00

4.50

5.00

Daily Block Proxy Subperiod Block

Proxy

13 HR MA Proxy 5 HR MA Proxy Shaped Proxy

$/MWh - (2009$)

10% Wind

20% Wind

(no EHV

Overlay)
30

Table 10: Shaped and Sub-period Block Proxy Analysis at 10% and 20% Wind Penetration

Shaped Proxy 1.74 1.81 1.39 1.45

Sub-period Block Proxy -Native 2.4 3.88 1.92 3.11

Sub-Period Block Proxy - Implied 

(including "exported" shape costs) 6.76 11.56 5.41 9.26

Proxy Type 2018 $/MWh 2009 $/MWh

10% Wind 

Penetration

20% Wind 

Penetration

10% Wind 

Penetration

20% Wind 

Penetration

As discussed throughout the report, a number of cost considerations are involved with 

incorporating wind in addition to the wind integration costs identified in this report, such 

as:

• Wind generation and transmission facilities installation and operation and 

maintenance.

• Effects on heat rates, emission rates, and outage frequency and duration from 

increased thermal unit ramping. The magnitude of these effects at high 

penetration rates is unknown, because utilities generally do not have specific 

operating experience yet.

• Feasibility and pricing of highly variable exports associated with high wind 

penetrations.

• Effects from external areas increasing their wind penetrations along with SPP and 

associated reduction of external system’s ability to absorb SPP wind variations.

• Lack of “shape” costs from the “shape proxy” methodology (as contained in the 

“daily block” proxy).

• Apparent need to consider the portion of the shape costs that get “exported” and 

do not show up in the calculated integration cost for the originating wind area.

Wind Integration Costs – Methodology and Proxy Resource Selection

The wind integration cost evaluation involves comparing the wind resource complete 

with its variability and uncertainty to an "ideal" proxy, or reference, resource by 

performing two simulations. The resulting adjusted production cost difference is the 

integration cost that can be normalized by dividing this result by the amount of wind 

generation being integrated. A key element in the determination of integration costs is 

the definition of the proxy resource. A second issue is whether or not the modeling 

approach addresses all the integration costs.
31

Conclusions

On the first issue the report does not definitively conclude what is the single best proxy 

resource for establishing wind integration costs for all conditions, but indicates the subperiod block best minimizes the concerns associated with other proxies – there is minimal 

energy shift from off peak to on peak periods (comparing to the daily block), but shape 

costs are captured (comparing to the shaped proxy). 

On the second issue, the report indicates that when including shape (or variability) costs 

by use of the block or moving average proxies, it is important to examine whether and 

what amount of these shape costs are being “exported” to external areas. Lastly, there are 

likely additional wind integration costs that are not yet identified by conventional 

modeling.

Closing Comments

In closing, the report must include a qualifying statement concerning how the study 

objectives were accomplished, and thoughts for future study are presented. 

Qualifying Statement

The results, findings, and conclusions presented here relate to the scenarios defined for 

the calendar year 2018. Critical to these scenarios are the extensive assumptions made 

regarding wind generation, load, fuel prices, energy market and operational structure, and 

certain aspects of policy regarding carbon. While the results paint a reasonably detailed 

picture regarding wind integration challenges and opportunities for NPA for the scenarios 

studied, care must be taken in extrapolating their meaning beyond the context in which 

they are presented in this report.

Objectives Statement

The ten study objectives listed earlier were fully accomplished as described in the study 

report. Some key components were use of NREL’s wind data base, wind penetration 

from 10% to 40%, statistical and PROMOD analyses, WAPA purchase scheduled on load 

net wind, SPP future market, large and active TRC, active utility and stakeholder 

participation in Nebraska, various approaches to integration cost evaluation, use of 

technical experts, and transfer of data to the utilities.

Thoughts for Future Study

Detailed thoughts are offered in the study report on what might be important and 

productive areas to investigate further if the opportunity should arise. In summary, these 

areas relate to:

• Additional work on integration cost concerning proxy resource definition, 

influence of interchange, influence of wind penetration in external areas, and 

influence of hurdle rate.
32

• More examinations of hourly specifics for generators and interchange, high 

wind/low load and low wind/high load periods, and extreme ramping situations.

• Transmission design, land use studies, and export studies.

• More wind capacity valuations, outside the current SPP criteria.

• More completely involve operational and transmission personnel.
F1146-E(10/2008)

REPORT DOCUMENTATION PAGE Form Approved

OMB No. 0704-0188

The public reporting burden for this collection of information is estimated to average 1 hour per response, including the time for reviewing instructions, searching existing data sources, 

gathering and maintaining the data needed, and completing and reviewing the collection of information. Send comments regarding this burden estimate or any other aspect of this 

collection of information, including suggestions for reducing the burden, to Department of Defense, Executive Services and Communications Directorate (0704-0188). Respondents 

should be aware that notwithstanding any other provision of law, no person shall be subject to any penalty for failing to comply with a collection of information if it does not display a 

currently valid OMB control number.

PLEASE DO NOT RETURN YOUR FORM TO THE ABOVE ORGANIZATION.

1. REPORT DATE (DD-MM-YYYY)

March 2010

2. REPORT TYPE

Subcontract Report

3. DATES COVERED (From - To)

4/2008 to 1/2010 

4. TITLE AND SUBTITLE

Nebraska Statewide Wind Integration Study: Executive Summary,

April 2008 - January 2010

5a. CONTRACT NUMBER

DE-AC36-08-GO28308

5b. GRANT NUMBER

5c. PROGRAM ELEMENT NUMBER

6. AUTHOR(S)

C. Johannes and D. Kallesen

5d. PROJECT NUMBER

NREL/SR-550-47285

5e. TASK NUMBER

WE10.4311

5f. WORK UNIT NUMBER

7. PERFORMING ORGANIZATION NAME(S) AND ADDRESS(ES)

Nebraska Power Association

P.O. Box 49

Columbus, NE 68602-0499

8. PERFORMING ORGANIZATION

REPORT NUMBER

AAM-9-89030-01

9. SPONSORING/MONITORING AGENCY NAME(S) AND ADDRESS(ES)

National Renewable Energy Laboratory

1617 Cole Blvd.

Golden, CO 80401-3393

10. SPONSOR/MONITOR'S ACRONYM(S)

NREL

11. SPONSORING/MONITORING

AGENCY REPORT NUMBER

NREL/SR-550-47285

12. DISTRIBUTION AVAILABILITY STATEMENT

National Technical Information Service

U.S. Department of Commerce

5285 Port Royal Road

Springfield, VA 22161

13. SUPPLEMENTARY NOTES

NREL Technical Monitor: Brian Parsons

14. ABSTRACT (Maximum 200 Words)

Wind generation resources in Nebraska will play an increasingly important role in the environmental and energy 

security solutions for the state and the nation. In this context, the Nebraska Power Association conducted a statewide wind integration study.

15. SUBJECT TERMS

Nebraska; wind; integration study; Nebraska Power Association.

16. SECURITY CLASSIFICATION OF: 17. LIMITATION 

OF ABSTRACT

UL

18. NUMBER 

OF PAGES

19a. NAME OF RESPONSIBLE PERSON

a. REPORT

Unclassified

b. ABSTRACT

Unclassified

c. THIS PAGE

Unclassified 19b. TELEPHONE NUMBER (Include area code)

Standard Form 298 (Rev. 8/98)

Prescribed by ANSI Std. Z39.18