Integrating Renewable Energy into the 

Electricity Grid 

Case studies showing how system operators 

are maintaining reliability 

PREPARED FOR 

Advanced Energy Economy Institute 

PREPARED BY 

Jurgen Weiss, PhD 

Bruce Tsuchida 

June 2015 
This report was prepared for Advanced Energy Economy Institute. All results and any errors are 

the responsibility of the authors and do not represent the opinion of The Brattle Group, Inc. or 

its clients. 

Acknowledgement: We acknowledge the valuable contributions of Judy Chang, Marc Chupka, 

Sam Newell, Frank Graves and other members of The Brattle Group for peer review. 

Copyright © 2015 The Brattle Group, Inc. 
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Table of Contents 

I. Executive Summary ..................................................................................................................... 3

II. Introduction ................................................................................................................................. 6

III. Trends in Renewable Integration in the United States ............................................................. 7

IV. Integrating Renewable Energy in ERCOT ............................................................................... 11

A. Nodal Pricing Market As Enabler ................................................................................... 12

B. CREZ Lines To Lower Wind Curtailment ...................................................................... 13

C. Improved Calculation of the Capacity Contribution of Wind ...................................... 14

D. Advances In Wind Forecasting ....................................................................................... 15

E. Technological Improvement of Renewable Sources ...................................................... 16

F. Redesign of Ancillary Services ........................................................................................ 16

G. Demand Response ............................................................................................................ 17

H. Pilot Projects in ERCOT .................................................................................................. 20

V. Integrating Renewable Energy at Xcel Energy Colorado ........................................................ 21

A. Change in Ancillary Services Requirements .................................................................. 22

B. Advanced Wind Forecasts ............................................................................................... 24

C. Advanced Operations ....................................................................................................... 25

VI. Other Innovative Approaches to Integrating Renewables ...................................................... 26

VII. Conclusions ................................................................................................................................ 30

VIII. Acronyms ................................................................................................................................... 32

IX. Bibliography ............................................................................................................................... 34
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I. Executive Summary 

A number of factors are contributing to increases in renewable energy production in the United 

States (and beyond). These factors include rapidly declining costs of electricity produced from 

renewable energy sources, regulatory and policy obligations and incentives, and moves to reduce 

pollution from fossil fuel-based power generation, including greenhouse gas emissions. While 

not all renewable energy sources are variable, two such technologies – wind and solar PV – 

currently dominate the growth of renewable electricity production. The production from wind 

and solar PV tries to capture the freely available but varying amount of wind and solar 

irradiance. As the share of electricity produced from variable renewable resources grows, so does 

the need to integrate these resources in a cost-effective manner, i.e., to ensure that total 

electricity production from all sources including variable renewable generation equals electricity 

demand in real time. Also, a future electric system characterized by a rising share of renewable 

energy will likely require concurrent changes to the existing transmission and distribution 

(T&D) infrastructure. While this report does not delve into that topic, utilities, grid operators 

and regulators must carefully plan for needed future investments in T&D, given the lead times 

and complexities involved. 

Rather, this report focuses on the fact that variable renewable generation adds a different new 

component to the challenges facing system operators in maintaining system reliability. For 

example, the decline in solar production at the end of the day can lead to significant ramping 

needs for grid operators. Dispatchable non-solar resources (existing fossil and hydro generation 

but also potentially demand resources) must be rapidly deployed to make up for the decline in 

solar PV generation at the same time that residential electricity demand is rising at the end of the 

day. Similar challenges can arise as a consequence of deviations in output from wind or solar 

facilities relative to weather forecasts over time periods ranging from minutes to hours. 

The question of integrating higher levels of variable renewable generation has recently been 

highlighted in the context of the U.S. Environmental Protection Agency’s proposed Clean Power 

Plan. An Initial Reliability Review (IRR)1 of the Clean Power Plan conducted by the North 

American Electric Reliability Corporation (NERC) raised concerns about the levels of renewable 

energy generation incorporated into EPA’s assumptions about what states could be expected to 

do to reduce greenhouse gas emissions. In an assessment of that IRR prepared for the Advanced 

Energy Economy Institute (AEEI), we found that NERC’s reliability concerns related to 

renewable energy integration were likely overstated, given the levels of renewable energy 

penetration already managed with no measurable compromise of reliability in some parts of the 

United States as well as in Europe.2 As a follow-up to that assessment, we have been asked by 

AEEI to provide an overview of what utilities and independent system operators (ISOs) with 

 

1 NERC, Potential Reliability Impacts of EPA’s Proposed Clean Power Plan, Initial Reliability Review, 

November 2014. 

2 Jurgen Weiss, Bruce Tsuchida, Michael Hagerty and Will Gorman, EPA’s Clean Power Plan and 

Reliability: Assessing NERC’s Initial Reliability Review, The Brattle Group, February 2015. 
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relatively high shares of variable renewable generation are doing to integrate those resources into 

their systems without compromising reliability. 

A survey of integration efforts in the United States and abroad reveals that the last decade has 

seen both a rapid increase in the deployment of variable renewable generation and 

improvements in their integration. 3 ISOs and utilities have at their disposal a large and 

increasing portfolio of options to accommodate large and growing shares of renewable generation 

while maintaining high levels of reliability. The options range from purely operational changes 

to possibilities that become available as a consequence of advancements in technology unrelated 

to renewable energy. Examples of the former include enhancing the coordination between 

balancing areas (including increasing their size), reinforcing the transmission system, and 

increasing participation of demand response. Examples of the latter include technological 

advances in weather forecasting, which, together with better data on historical performance of 

renewable energy, allows significantly improved forecasting accuracy of renewable generation; 

the proliferation of smarter infrastructure, much of it deployed at the customer site (smart 

meters, smart thermostats, smart appliances, all enabled by smarter software), enabling 

participation of increasing amounts of demand in activities that help mitigate the variability of 

renewable generation; and technological advances of renewable and complementary 

technologies (inverters, batteries) that allow renewable generators themselves to contribute to 

maintaining reliability. 

In this report, we provide two in-depth case studies, of the Electric Reliability Council of Texas 

(ERCOT) and Xcel Energy Colorado (a.k.a. Public Service Company of Colorado, or PSCo), to 

show how they integrate high shares of variable renewable energy. ERCOT (and the distribution 

utilities in ERCOT) and Xcel Energy Colorado have managed to successfully integrate increasing 

amounts of variable renewable energy resources at costs that have generally been small to 

modest.4 For example, ERCOT estimated the cost of integrating its first 10,000 MW of wind, 

approximately the capacity currently deployed, to be about $0.50 per MWh of wind generation.5

These organizations have used well-established and widely available methods and technologies 

such as: 

o changes in ancillary services, which manage short-term mismatches between electric 

supply and demand, with fast-ramping gas-fired generation, demand response, storage, 

and other technologies, 

 

3 For a recent survey of wind integration costs, see AWEA, Wind energy helps build a more reliable 

and balanced electricity portfolio. 

4 Throughout this report, integration costs do not include the costs of building new transmission, 

whether for the explicit purpose of connecting more renewable resources or for broader reasons. 

5 Milligan et al., Review and Status of Wind Integration and Transmission in the United States: Key 

Issues and Lessons Learned, NREL, March 2015, p.25. The cost estimate is based on an assessment of 

incremental spinning and non-spinning reserves required to manage both variability and uncertainty 

of wind production. 
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o improved forecasting of production from wind, 

o increased flexibility of fossil power plants on the system, 

o evolving capabilities of renewable generation itself to contribute to reliability, 

o expansion of transmission infrastructure (even though not an “integration measure” 

according to our use of the term), and 

o newer approaches under development, which include utilizing large-scale storage, 

dynamically managing the capacity of transmission lines, and allowing demand response 

to play a bigger role in managing system variability (and emergency situations). 

The success to date of ERCOT and Xcel Energy Colorado shows that integrating variable 

renewable energy at penetration levels of 10-20% on average and at times above 50% – i.e., high 

relative to the current levels in most of the United States – is possible. Integration challenges in 

other parts of the United States will differ due to both the mix of renewable resources and the 

make-up of the existing electric system. Nonetheless, by adopting approaches similar to those 

used (or planned) in ERCOT and Xcel Energy Colorado, ISOs/RTOs and utilities in other states 

should be able to integrate increasing shares of variable renewable generation using wellestablished tools and technologies. While infrastructure changes will likely be necessary in the 

longer term, the shorter-term integration challenges in many cases can be addressed with modest 

operational changes. 

Ongoing technological progress and ongoing learning by utility and ISO/RTO managers about 

best practices of managing the operations of electric systems with high renewable shares will 

likely allow the integration not only of the levels of variable renewable energy capacity now in 

places like Texas and Colorado but even larger amounts in the future. Specifically, integration of 

variable renewable energy at levels of penetration as high as those reliably managed by ERCOT 

and Xcel Energy Colorado, if not higher, should not be seen as a significant technical obstacle to 

compliance with EPA’s proposed Clean Power Plan. Rather, carefully examining the lessons 

learned in states and regions such as the ones examined here should help ISOs and utilities 

ensure that significantly larger amounts of variable renewable energy can be integrated at small 

to modest costs while maintaining high levels of reliability. 
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II. Introduction 

A number of factors are contributing to increases in renewable energy production. They include 

declining costs of electricity produced from renewable energy sources, regulatory and policy 

obligations and incentives, and moves to reduce pollution from fossil fuel-based power 

generation, including greenhouse gas emissions. While not all renewable energy sources are 

variable, wind and solar PV currently dominate the growth of renewable electricity production 

and their production tries to capture the freely available but varying amount of wind and solar 

irradiance. As the share of electricity produced from variable renewable resources grows, so does 

the need to integrate these resources at the lowest possible cost. Also, a future electric system 

characterized by a rising share of renewable energy will likely require concurrent changes to the 

existing transmission and distribution (T&D) infrastructure. While this report does not delve into 

that topic, utilities, grid operators and regulators must carefully plan for needed future 

investments in T&D, given the lead times and complexities involved. 

Recently, the question of integrating higher levels of variable renewable generation has come up 

in the context of the U.S. Environmental Protection Agency’s proposed Clean Power Plan. An 

Initial Reliability Review (IRR) of the Clean Power Plan conducted by the North American 

Electric Reliability Corporation (NERC) raised concerns about the levels of renewable energy 

generation incorporated into EPA’s assumptions about what states could be expected to do to 

reduce greenhouse gas emissions. In an assessment of that IRR prepared for the Advanced 

Energy Economy Institute (AEEI), we found that NERC’s concerns about reliability were likely 

overstated, given the levels of renewable energy penetration already managed with no 

compromise of reliability in some parts of this country as well as in Europe.6 In that assessment, 

we noted a number of technological and operational tools system operators were using to 

maintain reliability while managing systems with significant amounts of variable renewable 

generation. 

As a follow-up, AEEI has asked us to examine how system operators in the United States facing 

relatively high shares of variable renewable generation have adopted planning and operational 

practices to integrate renewable energy. They also asked to what extent technology, broadly 

speaking, has enabled larger contributions from renewable energy sources to the U.S. electricity 

supply without negatively impacting electric reliability. These technological impacts can be 

direct, by providing tools to help manage a more variable system (such as by deploying relatively 

small-scale storage), and indirect, by making possible changes in operational practices and 

market design also aimed at integrating renewables. Examples of the latter include advances in 

computing that improve forecasting, advances in inverter technology that allow more control 

over the output of non-synchronous generation (such as wind and solar PV) and hence their 

potential participation in redefined ancillary services markets, or advances in demand response 

and storage that enable the creation of entirely new ancillary services. We explored these issues 

 

6 Jurgen Weiss, Bruce Tsuchida, Michael Hagerty and Will Gorman, EPA’s Clean Power Plan and 

Reliability: Assessing NERC’s Initial Reliability Review, The Brattle Group, February 2015. 
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by highlighting case studies of successful integration of relatively high levels of variable 

renewable generation, specifically focusing on renewable integration efforts in the Electric 

Reliability Council of Texas (ERCOT) and Xcel Energy Colorado. 

ERCOT operates the smallest of the three independent interconnections in the United States and 

functions as the independent system operator (ISO) for nearly all of Texas. ERCOT is only 

weakly connected to surrounding electric systems, has very little hydro generation capacity and 

Texas has the highest installed wind capacity of any state with 12.5 GW installed. Xcel Energy 

Colorado operates a vertically integrated electric system with significant installed wind (and 

increasingly solar PV) capacity, but is not part of a regional transmission organization (RTO) or 

ISO. Wind meets close to 20% of Xcel Energy Colorado’s load on average and wind generation at 

times exceeds 50% of its instantaneous demand.7 Both systems provide a preview of a potential 

future with a higher share of variable renewable generation in the United States. It is noteworthy 

that both systems have achieved the integration of higher renewable penetration using 

traditional and well-established processes, tools and technologies rather than relying heavily on 

new or emerging technologies. 

In this report, we first summarize recent trends in renewable energy capacity and the knowledge 

of how to integrate renewable energy production. Then we discuss in detail integration measures 

planned or implemented in ERCOT and Xcel Energy Colorado. Finally, we highlight integration 

measures in other areas in a more summary fashion and provide some concluding remarks. 

III. Trends in Renewable Integration in the United States 

As shown in Figures 1 and 2, over the past decade wind capacity in the United States has 

increased tenfold and solar PV capacity almost hundredfold over the same time period. Over the 

same past decade, the share of solar PV and wind in total energy production has increased from 

about 0.4% in 2005 to 4.8% in 2014. 8 Nonetheless, a 2013 study demonstrated that wind 

generation in the United States still played a relatively minor role when compared to the 

contribution of wind in other countries. As shown in Figure 3, wind in the U.S. still contributes a 

relatively small share to overall electricity production when compared to the 15-40% 

contribution in several other (European) countries.9 

 

7 In May 24, 2013, wind provided electricity equivalent to 60.5% of Colorado’s total demand, eclipsing 

an earlier record of 56.7%. See http://www.aweablog.org/xcel-colorado-sets-u-s-record-with-over-60- 

wind/. 

8 U.S. Energy Information Administration, Electric Power Monthly, March 2015. 

9 In 2014, wind contributed 39.1% to Denmark’s electricity production (http://www.euractiv.com/ 

sections/energy/denmark-sets-world-record-wind-energy-311083). Solar PV and on- and off-shore 

wind produced a little less than 15% of Germany’s total electricity in 2014 (http://www.unendlichviel-energie.de/strommix-deutschland-2014). 
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Figure 1: Onshore Wind Installations in the United States since 2000

Source: AWEA, NREL 

Figure 2: Solar PV Installations in the United States since 2000 

Source: SEIA, U.S. Solar Market Insight, 2014 Year in Review, Executive Summary 

 
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Figure 3: Wind Share in Total Electricity Production in Selected Countries 

(Incremental Wind Penetration above 2006 Levels) 

Source: NREL, 2013 Wind Technologies Market Report (reproduced from Figure 4)

In the United States itself, the contribution of both wind and solar differs significantly by state, 

with nine states approaching the penetration levels seen in those European countries with the 

highest penetration levels.10 As renewable energy production has grown, so has the number of 

renewable integration cost studies and associated estimates of integration costs. Figure 4 shows 

these estimates of wind integration costs across a number of these studies. 

Figure 4 allows several observations. First, the estimated cost of integrating wind differs 

significantly across studies. While the bulk of estimates for wind penetration levels below 20% of 

peak load11 lie between $2-$5/MWh, there are several studies estimating costs in the $6-

$11/MWh range. The range of estimated integration costs is wider at higher penetration levels. A 

second observation is that on average, estimates of integration costs seem to be non-increasing 

over time even as wind penetration is increasing.12 Changing natural gas prices are likely one 

important reason, but it is also likely that progress is being made in understanding operating and 

capacity reserve requirements and minimizing costs by using a mix of better analytical tools and 

technology. In other words, electricity analysts, and RTO and utility operators have improved 

the methodologies for estimating integration costs, and helped expand the operational (and 

technology) options available for renewables integration. 

 

10 In 2013, nine states had wind and solar generation in excess of 10% of total demand: Iowa, South 

Dakota, Kansas, Idaho, Minnesota, North Dakota, Oklahoma, Colorado and Oregon (EIA, 

http://www.eia.gov/electricity/data/state/). 

11 Figure 4 reports integration cost as a function of increasing capacity as a percentage of peak load, 

rather than the more typically reported wind generation as a percentage of total demand. For example, 

ERCOT’s highest historic peak load was 68,305 MW. 11,154 MW of wind installed as of February 

Continued on next page 
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Figure 4: Wind Integration Levels and Costs across States and Years 

Source: NREL, 2013 Wind Technologies Market Report (reproduced from Figure 52)

A recent NREL report summarizes the key issues and lessons learned from integration studies 

and operational practices.13 In reviewing a number of both U.S. and international renewables 

integration studies, NREL identifies several key lessons learned. They include evidence that 

integration of large amounts of wind energy, up to 30% of total generation, is technically and 

economically feasible, with integration costs generally less than 10% of the cost per MWh of 

wind and often significantly less.14 It also appears that accumulated experience with increasing 

shares of renewable generation has led to many industry participants to revise their beliefs 

regarding the level of renewable generation would lead to excessive integration cost or 

potentially threaten system reliability. 

 

Continued from previous page 

2015 implies a penetration rate of 16.3% (for comparison with Figure 4) rather than the approximately 

10% of energy provided by wind in ERCOT in 2014. 

12 Integration cost estimates in the same region differ quite significantly year by year. For example, the 

integration cost estimates for Pacificorp moved from approximately $4.5/MWh at capacity penetration 

rates of about 10% in 2005 to about $5/MWh at 18% penetration in 2007, to between $9-10/MWh at 

15-18% penetration rates in 2010, to $2/MWh at penetration rates slightly above 20% in 2012. 

13 Milligan et al, Review and Status of Wind Integration and Transmission in the United States: Key 

Issues and Lessons Learned, NREL, March 2015. The large scale integration studies examined include 

three NREL studies (Western Wind and Solar Integration Study Phase 1 and Phase 2 and the Eastern 

Wind Integration and Transmission Study), an ISO New England wind integration study, an ERCOT 

wind integration study, and an IEA Task 25 wind integration study. 

14 Ibid, p.19. 
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A decade ago, the majority of industry experts might have believed that accommodating more 

than 20% of variable renewable energy sources without significantly changing the existing 

system would be impossible. Today, this threshold has moved to perhaps 30% and in some cases 

significantly higher, as highlighted by the renewable penetration levels examined in the most 

recent integration studies. Both ERCOT and Xcel Energy Colorado experience relatively high 

levels of wind generation– in the case of Xcel Energy Colorado at certain times on par with the 

highest penetration levels in Europe – and as ISOs/RTOs and utilities that have made significant 

progress in developing tools to better integrate large amounts of wind. For this reason, we turn 

next to exploring each of these two systems in more detail. 

IV. Integrating Renewable Energy in ERCOT 

In this section we explore various measures ERCOT has taken to facilitate the integration of 

wind (and other renewable energy sources). As shown in Figure 5, ERCOT has nearly 12.5 GW 

of wind capacity installed, and Texas is the state with the largest amount of installed wind in the 

United States in terms of MW installed. In 2014, wind energy contributed more than 10% to 

meeting ERCOT’s total demand, which means its wind penetration is approaching the levels of 

the European countries with the highest wind penetration rates.15 During some hours, wind 

production approaches 40% of total demand. 16 Also as shown in Figure 5, ERCOT analysis 

projects that wind penetration could almost double again over the next three years , which 

would bring the wind penetration as a percentage of load served near the top of global rankings. 

Beyond this fact, ERCOT also makes for an interesting case study in renewables integration 

because it is a relatively isolated electric system only weakly connected to other grids (through 

DC ties with the Eastern Interconnection and Mexico). Unlike some of the European countries 

with high wind (and solar) penetration, ERCOT, while relatively large, is not able to “lean” on 

neighboring systems to help mitigate the impacts of variable generation from renewables to the 

same degree as countries like Denmark or Germany. The absence of strong connections to 

neighboring regions is also important in the sense that the challenge of integrating variable 

renewable energy resources diminishes significantly as renewable generation sources are spread 

over a larger geographic area. 

 

15 As shown in Figure 3 above, six European countries have wind penetration levels above 10%, with 

three countries (Spain, Portugal and Ireland) approaching or exceeding 20% and one country 

(Denmark) exceeding 30%. 

16 On March 31, 2014, wind output reached 39.4% of total ERCOT load for a short period of time. See 

Trip Doggett, ERCOT Update, July 23, 2014. 
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Figure 5: Projected Annual and Cumulative Wind Installations in ERCOT

Source: ERCOT, Generator Interconnection Status Report, March 2015 

In the rest of this section, we describe in some detail various measures taken by ERCOT that 

have helped or are designed to help facilitate the integration of variable renewable energy 

sources. 

A. NODAL PRICING MARKET AS ENABLER

In December 2010 ERCOT introduced its Nodal Market, which allows locational marginal prices 

(LMPs), i.e., potentially different prices at many different geographic locations. This new market 

design provides more direct price signals to both generators and load and better reflects 

congestion in the transmission system. The LMP-based market allowed for a shift from portfoliobased scheduling and dispatch to resource-specific scheduling and dispatch, which facilitated 

better wind integration even though not undertaken explicitly for that purpose. At the same time 

as introducing the new market design, ERCOT also moved from a 15-minute dispatch resolution 

to a 5-minute resolution, which ERCOT identifies as “one of the main reasons why ERCOT has 

been successful in integrating renewables with minimal increase in Ancillary Services 
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capacity.”17 Moving towards shorter-term scheduling, which in turn permits taking into account 

better system information including more accurate forecasts of near future wind and solar 

generation, is recognized as an important operational tool for managing renewable output 

variability. 

B. CREZ LINES TO LOWER WIND CURTAILMENT

A second important set of actions designed to help better use and manage renewable energy 

sources was the construction of significant additional transmission capacity to areas with high 

wind potential but with insufficient transmission capacity. In 2005 the Texas State Legislature 

authorized the addition of significant transmission capacity into Competitive Renewable Energy 

Zones (CREZ), a process that was completed in 2014. The lines were intended to expedite 

construction in areas where renewable generators were committed to building, and were 

designed to accommodate a total wind capacity of 18,500 MW18 (as Figure 5 above shows, this 

level could well be exceeded in the near future, even if not all of the additional wind is built in 

the areas connected through CREZ lines). 

Prior to the CREZ lines being built, West Texas, where most of the wind capacity was located, 

experienced significant instances of negative LMPs and curtailments. Negative prices result when 

total supply from resources that either must run (such as inflexible baseload plants) or lose nonenergy revenues if not producing (such as production tax credits and renewable energy 

certificates for wind plants) exceeds demand. Negative prices are therefore a sign of a significant 

supply-demand mismatch, given available transmission capacity. In extreme cases, the excess 

supply becomes so large that maintaining system reliability requires curtailing some generation 

(such as wind). Both negative prices and curtailments are therefore evidence that not enough 

transmission capacity exists to deliver power generated by a wind plant (even at zero or negative 

offer prices) to customers willing to pay for it.19 Additional transmission lines from wind-energy 

producing regions to demand centers alleviate both negative pricing and curtailments. The 

completed CREZ lines – for a cost of approximately $6.8 billion – are credited with significantly 

contributing to lower wind curtailment since 2012, from levels as high as 17% in 2009 to 1.6% in 

2013,20 and with mostly eliminating negative prices.21 It should be noted that the cost of the 

 

17 ERCOT, ERCOT Concept Paper: Future Ancillary Services in ERCOT, Draft Version 1.1, 2013, p.8. 

18 http://www.texascrezprojects.com/overview.aspx. 

19 In addition to facing curtailment from insufficient transmission offtake capacity, negative bids are a 

result of the way in which wind development receives tax incentives proportional to output. Some 

generation companies regard this as a policy that distorts markets and makes wind expansion 

undesirable. While an important issue in public policy towards encouraging new technologies, this is 

a political side effect and not a true integration issue. 

20 Lori Bird, Jaquelin Cochran, and Xi Wang, Wind and Solar Energy Curtailment: Experience and 

Practices in the United States, NREL, March 2014, p.9. 

21 See http://www.eia.gov/todayinenergy/detail.cfm?id=16831. 
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CREZ lines is in addition to the modest integration cost estimates outlined above and that it has 

led to an active debate about who should bear the cost of additional transmission infrastructure.22

C. IMPROVED CALCULATION OF THE CAPACITY CONTRIBUTION OF WIND

Ensuring resource adequacy is one of the primary concerns of electric system operators. Models 

for estimating the contribution of conventional fossil generation sources to resource adequacy 

have been used for decades. For variable generation, however, efforts to develop appropriate 

metrics are less established and continue to evolve. Understanding the contribution of variable 

renewable energy resources to meeting peak demand is critical for managing a system with 

increasing shares of renewable generation. Assuming that variable renewable resources do not 

contribute to resource adequacy is still a common practice in several countries and regions, 

including some of the European countries with high penetration of renewables. The practice is 

often justified with the argument that since output cannot be controlled (at least not in the 

positive sense – it can be curtailed) by the system operator, the system cannot “count” on the 

production from such generators. However, in electric systems with a resource adequacy 

requirement (unlike ERCOT), this approach can result in additional costs beyond what is 

necessary, since it ultimately requires end users to pay for more capacity than is actually needed 

when properly assessing resource adequacy needs.23 

In the United States, system operators typically give some capacity value to variable renewable 

generation. An often used approach for assessing this contribution is called “Effective Load 

Carrying Capability” (ELCC). ELCC estimates the statistical relationship between demand and 

the expected contribution from a given generation resource using various modeling techniques 

and data sources including observed actual generation during historic peak load conditions. 

Until late last year, ERCOT used an estimated ELCC of 8.7% for wind generators no matter 

where in ERCOT they were located.24 Recently ERCOT updated its ELCC estimates for wind 

generation based on actual observed capacity factors during peak load conditions. The result was 

an increase in the estimated contribution of wind to resource adequacy and a differentiated 

assessment of that contribution by region. Specifically, as of November 2014, ERCOT is 

determining wind’s capacity contribution is based on up to the ten previous years of wind 

production during the 20 highest peak hours during the summer and winter peak load season 

respectively.25 For solar PV, ELCC is assumed to be 100% of capacity up to 200 MW of solar PV 

 

22 In August 2014, the Public Utilities Commission of Texas initiated a project to review the cost 

allocation of renewable energy production related transmission and ancillary services (PUCT Project 

No. 42647) with a set of questions including whether or not renewable resources should help fund 

further transmission investments. See PUCT, Memorandum, August 6, 2014). 

23 ERCOT is an energy-only market without a resource adequacy requirement. 

24 ERCOT, Report on the Capacity, Demand, and Reserves in the ERCOT Region, 2015-2024, February 

2014. 

25 ERCOT, NPRR Number 611, Board Report, October 14, 2014. 
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installed, and subsequently the actual average capacity factor during the 20 highest peak periods 

of the preceding three years during the summer and winter peak load season, respectively.26 

As a consequence, as of November 1, 2014 wind in non-coastal regions is contributing to reserve 

margins with 12% of nameplate capacity during the Summer Peak Load Period and 19% during 

the Winter Peak Load Period. Coastal wind is contributing 56% during the Summer Peak Load 

Period and 36% during the Winter Peak Load Period. Solar PV, which is currently under 200 

MW in installed capacity, is contributing 100%.27 Relative to the previous calculation, the new 

methodology increased expected reserve margins by approximately 2% (from 13.7% to 15.7% in 

2015 and from 4.9% to 7.3% in 2024).28 The new methodology suggests that ERCOT actually has 

higher reserve margins than was estimated under its old methodology and will need to attract 

fewer additional resources to maintain target reserve margins going forward, all else equal. This 

in turn means that the estimated cost of a system with higher renewable share is less – since 

fewer total resources are needed to maintain adequate reserve margins than under the old 

methodology. 

In ERCOT, this accounting change does not directly affect costs, since ERCOT does not have a 

resource adequacy requirement and wind’s capacity credit does not displace other capacity 

resources. Wind displaces other capacity resources only to the extent that its output reduces 

energy prices across the year, and thus deters entry or promotes retirements. However, in other 

systems that have resource adequacy requirements, capacity accounting does affect costs more 

directly, as each MW of wind credited reduces the amount of other capacity needed. 

D. ADVANCES IN WIND FORECASTING

While there is and has been significant wind development activity on the Gulf Coast, ERCOT’s 

large wind capacity is still relatively geographically concentrated in West Texas and the Texas 

Panhandle, which reduces the diversity benefits that would result from wind resources being 

more equally spaced across a wider area. 29 As a consequence, changes in meteorological 

 

26 Ibid. 

27 ERCOT, Report on the Capacity, Demand, and Reserves in the ERCOT Region, 2015-2024, December 

1, 2014. 

28 To estimate the change in reserve margin, we used the December 1 ERCOT report on the Capacity, 

Demand, and Reserves in the ERCOT Region, 2015-2024 from December 1, 2014, available in 

spreadsheet form from ERCOT’s website, and replaced the applied new capacity contribution factors 

with the previously used 8.7%. 

29 As of 2014, wind capacity on the Gulf coast represented about 14% of total ERCOT wind capacity 

(Texas Wide Open For Business, The Texas Renewable Energy Industry, 2014, p. 13-14). Research 

shows that short term variability of wind output can be mitigated relatively easily by interconnecting 

wind output from a relatively small set of geographically diverse sites. See Warren Katzenstein, Emily 

Fertig, Jay Apt, The variability of interconnected wind plants, Energy Policy 38, 2010, p. 4400-4410. 

Also, as indicated above, coastal wind in ERCOT is better correlated with demand in major load 

centers. 
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conditions can lead to rapid changes in wind output, which in turn can require large ramping (up 

or down) from the rest of the ERCOT resources. ERCOT has improved its weather forecasting 

capabilities over the past several years. ERCOT has also implemented the ERCOT Large Ramp 

Alert System using probabilistic wind forecasts for the next six hours updated every 15 minutes. 

This system permits operators to commit resources during the day with a much better 

understanding of the likelihood of needing additional resources for large ramping events caused 

by changes in wind production.30 

E. TECHNOLOGICAL IMPROVEMENT OF RENEWABLE SOURCES

Technological advances related to renewable energy resources themselves can facilitate their 

integration with the electric system. One example of the co-evolution of operational procedures 

and technological capabilities is ERCOT’s requirement that wind generators, having signed 

interconnection agreements on or after November 1, 2008, need to provide voltage ride-through 

capabilities – that is, the ability to continue operating during short-term periods of voltage 

fluctuation rather than automatically shutting down.31 As a consequence, these newer wind 

generators do not have to disconnect when system voltage levels rise above or fall below the 

target level of 60 Hz. Absent voltage ride-through capability, the system operator has to set aside 

sufficient resources to be able to react to a potentially large set of generating resources (in this 

case wind generators) disconnecting from the system, which might turn a small problem into a 

much more severe one. 

F. REDESIGN OF ANCILLARY SERVICES

Another important area of activity related to renewables integration is ERCOT’s redesign of 

ancillary services markets, as part of its Future Ancillary Services (FAS) proposal. 32

Implementation of FAS may depend partly on the results of ERCOT’s benefit cost analysis of the 

proposal, due out later in 2015. This redesign is driven by the perceived need to meet future 

system demands as the penetration of variable energy resources increases, while also 

accommodating new opportunities to meet those needs. It aims to incorporate a variety of 

advanced energy technologies into the marketplace, including faster ramping thermal 

generation, energy storage, automated DR, distributed generation, and renewable generation. 

For example, FAS introduces a new product called Fast Frequency Response 1 (“FFR1”) that 

advanced batteries and fly-wheels can provide. Load resources (discussed in more detail below) 

could also provide a Fast Frequency Response product called “FFR2,” similar to how they provide 

responsive reserves today. ERCOT estimates that approximately 1,400 MW of load resources are 

 

30 Pengwei Du, ISO Experiences with Stochastic Wind Forecasting – ERCOT, ERCOT. 

31 ERCOT, ERCOT Nodal Operating Guides, Section 2: System Operations and Control Requirements, 

February 1, 2014, p.2-25. 

32 ERCOT, ERCOT Concept Paper: Future Ancillary Services in ERCOT, Draft Version 1.1, 2013, p.9 
17 | brattle.com

capable of meeting the requirements of FFR2.33,34 Both types of FFR would provide more rapid 

frequency response than traditional resources to compensate for sudden unplanned outages at 

large thermal units. Current proposals would require FFR resources to deliver their full response 

within a half second. 

In the longer term, ERCOT is also raising the question whether a shift from conventional fossil 

to more variable renewable generation may lead to a loss of system inertia, which is traditionally 

supplied by synchronous generation (spinning generators, typically generators with spinning 

mass such as fossil fuel or hydro resources). This concern, if validated, may merit, at some point 

in the future, the introduction of some new ancillary service to incentivize Synchronous Inertial 

Response Service (SIR). In that context ERCOT is also evaluating to what extent synthetic (or 

emulated) inertia from inverter-based generation sources (such as wind turbines) might be able 

to provide the necessary capabilities in the future. While practical experience with wind 

generators providing synthetic inertia is limited, it appears that at least under some conditions 

inverter (or equivalent) technologies can provide some of the inertia services typically provided 

by synchronous equipment.35

G. DEMAND RESPONSE

Demand response (DR) is playing an increasing role in providing capacity, but also in mitigating 

shorter term events potentially impacting reliability. While DR is primarily used as a capacity 

resource, i.e. as a way of ensuring that the combination of supply resources and DR are sufficient 

to maintain a stable supply of electricity, particularly during the periods of highest demand, it is 

also used for emergency situations, such as when generation outages lead to relatively short term 

supply shortages. Many DR programs limit the number of times, and define lengths of time for 

such calls, each year and do not require advanced technology. For example, interruptible load 

contracts using some form of direct load control (DLC) have been around for many years. These 

types of “traditional” DR can help grid operators manage any relatively rapid and unexpected 

changes in the output from variable renewable energy sources. However, in the future advances 

in technology such as smart meters (defined as meters that measure consumption at frequent 

intervals and/or allow for frequent bidirectional communication), home energy management 

systems, smart appliances, etc. will increasingly create additional opportunities to use DR in 

 

33 Unlike most other system operators that secure operating reserves mostly through generator 

resources, ERCOT has been allowing load to provide operating reserves for ten years. Today, out of 

the operating reserve requirements of 2,300 MW (or higher), these load resources provide 

approximately 1,250 MW of responsive reserves. See http://www.ercot.com/content/meetings/wms/ 

keydocs/2004/0923/WMS09232004-8.doc and http://www.ercot.com/content/gridinfo/resource/2015/ 

adequacy/cdr/CapacityDemandandReserveReport-May2015.pdf. 

34 ERCOT, ERCOT Concept Paper, Future Ancillary Services in ERCOT, Draft Version 1.1, p.19. 

35 In addition to requiring all wind generators to be capable of high- and low voltage ride through, 

Hydro Quebec already requires wind plants with 10 MW or greater capacity to be capable of 

providing emulated inertia. See Hydro Quebec, Transmission Provider Technical Requirements For 

The Connection Of Power Plants To The Hydro-Québec Transmission System, p.61. 
18 | brattle.com

situations other than emergencies. More robust DR can therefore make a significant contribution 

to integrating larger amounts of renewables. 

Over the past five years ERCOT has changed its programs allowing participation by DR, which 

include a number of distinct products, all essentially targeting “traditional” DR: weather and 

non-weather sensitive Emergency Response Service Ten Minute (ERS-10) and Emergency 

Response Service Thirty Minute (ERS-30), both of which are emergency interruptible load 

services. Procurements during 2014 resulted in contracts for between 450 MW and 630 MW of 

non-weather sensitive ERS-10 and between 97 MW and 280 MW of non-weather sensitive ERS30. There is currently no contracted weather-sensitive ERS-10 and 21.6 MW of weathersensitive ERS-30. 

ERCOT also has a load-based 10-minute responsive reserve ancillary service, which targets larger 

customers connected through two-second demand data meters for non-emergency services. In 

theory, both controllable and non-controllable Commercial Load Resource (NCLR and CLR) 

programs exist. As of January 1, there were 232 load resources corresponding to 3,056 MW 

registered with ERCOT. All but two were non-controllable resources, meaning that they provide 

Responsive Reserves Service (RRS) using high set underfrequency relays (UFRs). These resources 

bid into the day-ahead market and up to a total of 50% of the RRS awards can be made to load 

resources. During 2014, the average award of RRS to load resources was approximately 1,350 

MW.36 Finally, the Four Coincidental Peaks (4CP) program encourages load resources to lower 

peak demand during the highest load hour in each of the four summer months (June through 

September) since the customers’ share in transmission and distribution costs depends on the 

magnitude of those peaks. ERCOT estimates the impact of the 4CP program (which does not 

provide explicit signals for DR, but rather relies on loads to lower their peaks, which may or may 

not coincide with high prices or changes in market conditions caused by fluctuations in variable 

generation) to be between 830-950 MW.37 

The rapid deployment of smart meter technology, which by February 2015 had reached 6.7 

million representing 98.4% of ERCOT load,38 is providing the basis for increasing participation of 

residential load resources in demand response. For example, the ERS-30 program, which requires 

generation or load reductions to be made available in emergency situations within 30 minutes, is 

increasingly attracting residential customers. In the summer of 2014, ERCOT awarded three ERS 

contracts to Qualified Scheduling Entities (QSEs), which in turn included three residential 

aggregations initially involving approximately 60,000 residential participants for a total of 21.6 

MW of peak demand (between 1 PM and 8 PM).39 

 

36 ERCOT, Annual Report of Demand Response in the ERCOT Region, Version 1.0, March 2015. 

37 Ibid. 

38 ERCOT, ERCOT Monthly Operational Overview, February 2015, p.41. 

39 Paul Wattles, Item 9: Demand Response Update, August 12, 2014. 
19 | brattle.com

ERCOT’s emergency response DR programs have already played a significant role in helping 

maintain system reliability. For example, on January 6, 2014, cold winter temperatures were 

exacerbated by unplanned outages of several generation sources. As a consequence, ERCOT 

declared an emergency and activated 111 MW of ERS-30 and 509 MW of ERS-10 resources for 

approximately one hour.40 During the same event on January 6, ERCOT had previously activated 

1,080 MW of ancillary services using load resources.41

ERCOT also created an opportunity for loads to more actively participate in markets during peak 

load conditions, essentially allowing for price-sensitive bids in real-time markets.42 Called “Loads 

in SCED (Security Constrained Economic Dispatch)”, a first version of the program only open to 

Load Serving Entities (LSEs) went into operation on June 1, 2014. To date, ERCOT has seen 

limited interest in participation. As of the summer of 2014, between 25-30 MW of aggregated 

residential demand from air conditioning, water heaters and pool pumps under direct load 

control were in the qualification process.43 However, no resources are currently participating in 

the program. 

A second, more comprehensive version of the program open to Curtailment Service Providers 

(CSPs), i.e. 3rd party DR providers, currently is under discussion. Full implementation of these 

programs would allow participating customers to offer to reduce their consumption when prices 

are high in real-time, enabling ERCOT to match supply with demand at least cost using both 

supply and demand resources. Beyond these programs, ERCOT is also examining the potential 

future role of DR in the provision of ancillary services.44

Beyond ERCOT’s own programs, the ERCOT energy-only market with full retail choice also 

provides ample opportunities for Retail Energy Providers (REPs) to offer rates and incentives that 

encourage demand participation in ways that mitigate high prices, typically associated with 

relatively high net loads. Offering various retail rate structures allow REPs to differentiate 

themselves from their competitors and allow their customers to reduce costs by being priceresponsive. By creating price-responsive demand, these programs have the potential to mitigate 

the impacts of variations in renewable energy production before emergency situations arise. 

A number of the programs offered by REPs rely on technology such as smart meters, smart 

thermostats etc. While the high penetration rates of smart meters is no longer a barrier to the 

deployment of such programs, increases in the penetration levels of smart thermostats – which 

allow remote control of air-conditioners and electric heating systems, for example in response to 

price spikes caused by a drop-off in renewable generation – and other enabling technology 

 

40 ERCOT, Final Report: January 6 2014 EEA, March 7, 2014, p.7. 

41 Ibid. 

42 ERCOT, Nodal Protocol Revision Request (NPRR) 555, Load Resource Participation in SecurityConstrained Economic Dispatch, posted July 3, 2013. 

43 Paul Wattles, Item 9: Demand Response Update, August 12, 2014, p.9. 

44 Paul Wattles, ERCOT ISO and DR Overview 2014, May 21, 2014. 
20 | brattle.com

increase the potential for such programs to expand in the future. As of 2014, ERCOT estimates 

the REP based programs contributed approximately 432.5 MW of DR, about half from pricing 

programs (real time pricing, Block and Index pricing, etc.) and half from load control programs.45

As of mid-2013, 4,105 customers were enrolled in real time pricing programs, 22,947 in 

block+index46 programs and 117,570 in other Time of Use (ToU) pricing programs.47 

There is some indication that the number of enrolled customers is increasing relatively quickly. 

The majority of time-sensitive ToU tariffs to-date involve “free weekends and evenings” type 

programs. While not yet a major factor in helping with grid reliability and variable renewable 

integration, the combination of smart meter infrastructure and an increasing acceptance of timeresponsive tariff designs creates a basis for the development of more sophisticated tariff 

structures designed at making load more flexible in direct response to price fluctuations, 

including those driven by variable renewable generation. 

H. PILOT PROJECTS IN ERCOT 

In addition to the changes made by ERCOT and described above, there are also a number of 

other early stage/pilot programs not administered by ERCOT but occurring inside its territory 

with important implications. 

Oncor, the largest regulated transmission and distribution system operator in ERCOT, was one of 

two participants in a Department of Energy funded pilot project involving Dynamic Line Rating 

(DLR) completed in 2013.48 DLR dynamically increases transfer limits relative both to the static 

ratings typically used in utility operations and to ambient-adjusted (AAR) line ratings based on 

ambient conditions of the physical transmission line, such as temperature, wind, and humidity, 

or based on the direct measurement of line sag. Lower temperature and higher wind help cool 

the physical wires and therefore allow higher transfers of power without sagging as much from 

the heat produced by current flow. 49 Two important potential application of DLR are for 

congestion mitigation and planning. Oncor, in its evaluation of the DLR pilot, notes that “Study 

results show that congestion mitigation can be obtained with as little as a 5 to 10% increase in 

capacity over the currently used ambient-adjusted line ratings. The effective congestion 

mitigation can be in the range of 60 to 100% on the lines monitored.”50 While the pilot did not 

 

45 ERCOT, Annual Report of Demand Response in the ERCOT Region, Version 1.0, March 2015, p.7. 

46 Under Block+Index pricing, customers pay a certain amount for a certain number of kWh (block). For 

consumption above the block, pricing is indexed to wholesale prices. 

47 Paul Wattles, Demand Response Update, ERCOT, October 24, 2014, p.9. 

48 The other participant was the New York Power Authority (NYPA). 

49 See Oncor West Texas Dynamic Line Rating (DLR) Project presentation, dated March 26, 2013, available 

at: http://www.ercot.com/content/meetings/rpg/keydocs/2013/0326/Oncor_W_Texas_Dynamic_Line_ 

Rating_Presentation_for_ERCOT_032.pdf. 

50 Oncor Electric Delivery Company, Dynamic Line Rating, Oncor Electric Delivery Smart Grid 

Program, Final Report, August 2013, p.2. 
21 | brattle.com

provide definitive answers, Oncor did find that 5% DLR use increased average wind generation 

by 3%, which, given that only half of the lines of the pilot involved wind generation, Oncor 

deemed significant.51 In other words, Oncor found that the use of DLR allowed increased levels 

of wind generation during contingency events without causing congestion. 

Other recent examples of early stage experiments include the use of smart meters to measure 

voltage levels (and resulting voltage profiles) at the meter level, to use this data to develop 

feeder-level voltage profiles and to use those profiles to predict transformer outages. At least one 

utility in Texas is examining how this data can be used to better manage the maintenance and 

replacement of transformers in ways that both lowers the chance of outages and reduces the cost 

of maintaining a reliable distribution system. It can be expected that as the share of distributed 

variable renewable energy sources, most likely solar PV, increases, the benefits of being able to 

measure voltage profiles at this level will help reduce transformer outages and the costs related to 

integrating such resources.52 

Similarly, current battery pilot programs suggest that the benefits of this kind of storage, installed 

at the feeder level and serving just a few customers, could substantially exceed those traditionally 

estimated. Preliminary pilot results have shown that in local outage situations, when batteries 

keep a group of customers supplied with electricity, dramatic behavior changes are seen such 

that customers maintain essential services for much longer than initially expected based on a 

given storage capacity.53 While very preliminary, these results point to the potential interaction 

benefits of renewables, storage and behavioral changes (such as turning off non-essential 

equipment) during stress periods for local distribution systems. Such stress periods could be 

caused by external events such as storms, but also by unforeseen variability in renewable energy 

production at high penetration levels. 

V. Integrating Renewable Energy at Xcel Energy Colorado 

Xcel Energy Colorado is a vertically integrated utility providing electric service to approximately 

1.3 million wholesale and retail customers in Colorado, including the Denver metropolitan area. 

Xcel Energy is among the utilities with the highest renewable energy penetration and is 

recognized as a leader in renewable energy integration, having been ranked first by the 

American Wind Energy Association (AWEA) for eleven consecutive years and fifth by the Solar 

 

51 Ibid, p. 168. 

52 Based on confidential information provided by one of ERCOT’s distribution utilities. 

53 Based on confidential information provided by one of ERCOT’s distribution utilities, a battery system 

designed to provide one hour of back-up power was able to sustain essential services for up to four 

hours as a result of customers connected to the storage system dramatically reducing their demand 

during the periods when storage was needed to supply power not available from the grid. 
22 | brattle.com

Electric Power Association (SEPA). 54As of the end of 2013, Xcel Energy Colorado’s wind 

portfolio comprised 2,168 MW of wind capacity with another 450 MW to be connected in the 

near future. In addition, the system has 188 MW of customer-sited solar generation and 80 MW 

of utility scale solar PV capacity, which is expected grow by 170 MW in the near future.55 The 

balancing area’s peak load in 2013 was 6,646 MW and wind contributed 18.7% to Xcel Energy 

Colorado’s annual load.56 Xcel Energy Colorado is not part of an RTO and does not operate a 

formal day-ahead or real-time energy market. All these attributes create challenges that make 

Xcel Energy Colorado a good case study for integrating variable renewable energy sources by a 

single utility. 

With the goal of increasing renewable penetration levels, Xcel Energy Colorado has been 

addressing the system operational issues with the focus on changes in ancillary service 

requirements, improved wind forecasting, and increases in generation flexibility. 

A. CHANGE IN ANCILLARY SERVICES REQUIREMENTS

While the summer peak load for the Xcel Energy Colorado system is approximately 6,700 MW, 

the system load during off-peak hours can drop to around 2,700 MW. This indicates that the 

system could have over 2,600 MW of wind generation potentially serving a 2,700 MW load. 

Given the magnitude of installed wind capacity, wind ramping events, specifically ramp-down 

events (i.e. periods when electricity production from wind decreases relatively rapidly), have 

been identified as a potential reliability concern.57 Unlike ramp-up events, there are no wind 

turbine control actions available to mitigate the ramp-down events, leaving improved forecasting 

as the primary tool to provide the system operator adequate foresight to plan for increased 

resource needs. This leads to the need for advanced energy resources like automated demand 

response, energy storage and other fast ramping resources. 

For resource planning, Xcel Energy Colorado determines the generation capacity to be kept 

available, similar to other system operators. However, Xcel Energy Colorado also determines the 

responsiveness, flexibility, or ability of that generation to be brought on-line in a timely manner 

to address the needs for flexibility. Consequently, in 2011 it adopted a 30-minute Wind Reserve 

Guideline to ensure that enough standby generation capability can be brought on-line within 30-

 

54 www.xcelenergy.com/Company/News/News_Releases/Xcel_Energy_named_No._1_utility_wind_ 

provider_for_11th_consecutive_year. 

55 Public Service Company of Colorado, Xcel Energy, Operating Companies Joint Open Access 

Transmission Tariff - First Revised Volume No. 1, filed with the Federal Energy Regulatory 

Commission, May 15, 2014, p. 2. 

56 Ibid. 

57 Ramp-up events, with continued or sustained increases in wind generation levels, are dealt with by 

reducing the level of generation from gas-fired units, or in severe cases, shutting down a gas-fired unit 

or curtailing wind. In general, ramp-up issues will have economic implications but not necessarily 

lead to reliability issues. On the other hand, ramp-down events can potentially lead to a shortage of 

overall generation, which is a reliability concern. 
23 | brattle.com

minutes to cover the needed flexibility. The flexible capacity need was calculated to be a MW for 

MW match against wind generation for the first 290 MW.58 For wind generation levels above the 

290 MW threshold, additional 30-minute capable standby generation is held based on the 

aggregate wind energy being produced from wind facilities located along the northern Colorado 

border within Energy Resource Zone (ERZ) 1, which contains the majority of Xcel Energy 

Colorado’s wind resource.59 Figure 7 shows the calculated flexibility needs as a function of wind 

generation.60

Figure 7: 30 Minute Reserve Needs and Wind Generation Level 

Partly in response to rapidly increasing wind (and solar) penetration, Xcel Energy recently asked 

the FERC for changes to its Open Access Transmission Tariff (OATT), in particular the amount 

of certain ancillary services it procures and how it recovers the resulting costs. Specifically, it 

asked the FERC to approve changes to its Regulation and Frequency Response Service (Schedule 

3 of its OATT) and to approve the formal introduction of a Flex Reserve Service (Schedule 6A of 

its OATT) specifically designed to handle large reductions in wind generation due to losses in 

wind speed (and hence occurring over a somewhat longer period of time, between tens of 

minutes and hours). The addition of a Flex Reserve service can by itself be considered an 

 

58 This 290 MW threshold was determined in 2011 and may change in the future as the Xcel Energy 

Colorado resource portfolio, including wind and solar, changes. 

59 As of 2011, out of the five ERZs, only ERZ 1 and 3 had wind resources, with future wind resources 

planned for ERZ 2. At the time, over 80% of all Xcel Energy Colorado’s wind resources were located 

in ERZ 1. The calculation method based on ERZ 1 wind generation may also change with future wind 

locations. 

60 Source: Xcel Energy Colorado 2011 Wind Limit Study, filed as part of the 2011 Electric Resource Plan, 

available at: http://xcelenergy.com/staticfiles/xe/Regulatory/Regulatory%20PDFs/PSCo-ERP-2011 

/Attachment-2.14-1-2011-Wind-Limit-Study.pdf
24 | brattle.com

innovation in systems operation designed to better integrate variable renewable energy 

resources. We note that the amount of additional ancillary service costs to be recovered is 

$727,000 per year, or only 0.3% of its $230 million annual transmission revenue requirement.61

B. ADVANCED WIND FORECASTS

In parallel to adding the 30 minute flexibility to accommodate increased net load variability and 

ramping events, Xcel Energy has been advancing its wind forecast methods. As a stand-alone 

utility lacking geographic diversity, the value of forecast accuracy for the variable resources is of 

particular importance. Furthermore, the same level of forecast error translates into greater 

absolute errors as renewable penetration levels grow. 

In 2009 Xcel Energy implemented an advanced wind forecasting system. The system, developed 

in collaboration with the National Center for Atmospheric Research (NCAR), blends forecasting 

and statistical methods.62 The system uses a variety of inputs from satellites, planes, radars, 

ground-based weather stations, and sensors on the wind turbines themselves and produces a new 

forecast every 15 minutes.63 It improved the wind forecast accuracy by 35% relative to previous 

forecast methods and informs both day-ahead and real time operations. Since the introduction of 

the improved methodology, Mean Absolute Error (MAE) in wind forecasting has decreased 

significantly. In Colorado, MAE dropped from 18.01% in 2009 to 11.04% by 2013 (a 38.7% 

reduction) with resulting savings of $20.4 million.64 

These findings are consistent with the evidence from other jurisdictions that over time wind 

forecast accuracy has increased and integration costs have fallen. For example, Eurelectric, the 

European industry association for the power industry, cites wind forecast improvements as one 

of the measures improving the integration of variable renewables, and includes Figure 8 in a 

recent report on the topic.65

 

 

 

61 FERC, Order Conditionally Accepting And Suspending Proposed Tariff Revisions, Subject To Refund, 

And Establishing Hearing And Settlement Judge Procedures, Dockets Nos. ER14-1969-000, ER14-

1969-001 and ER14-1969-002, Issued December 5, 2014, p.3. 

62 For a detailed description of the system, see Mahoney et al., A Wind Power Forecasting System to 

Optimize Grid Integration, IEEE Transactions on Sustainable Energy, Vol. 3, No. 4, October 2012. 

63 https://www2.ucar.edu/atmosnews/news/5771/ncar-wind-forecasts-save-millions-dollars-xcel-energy. 

64 Drake Bartlett, What is the value of a Variable Generation Forecast? Xcel Energy, February 25, 2014. 

65 Eurelectric, Integrating intermittent renewables sources into the EU electricity system by 2020: 

Challenges and solutions, 2010. 
25 | brattle.com

Figure 8: Changes in Wind Forecast Accuracy in Spain 

Source: Eurelectric, 2010, Reproduced Picture 10 

C. ADVANCED OPERATIONS

In addition to the ancillary services and forecast improvements, Xcel Energy Colorado has 

advanced operations to better accommodate renewable resources and reduce overall production 

cost. These operational advancements expand beyond the thermal generators that traditionally 

provided the flexibility needed to reliably operate the system. 

For example, in 2010 Xcel Energy Colorado made technological modifications to its Fort Saint 

Vrain 750 MW combined cycle gas plant that lowered the minimum generation level by 300 

MW and increased the turn-around time (the time needed between shut-off and restart of the 

plant) from 8 hours to 2 hours. Also, many of Xcel Energy Colorado’s newer gas turbines were 

updated with the GE FastStart technology, which improved the start-up time of these units. 

Similarly in 2011 the minimum generation level of the Comanche #3 coal-fired power plant was 

lowered from 500 MW to 405 MW.66 Along with these improvements, a number of coal units 

have been, or are in the process of being, retired. Cherokee unit #4 is being converted from 

burning coal to gas. In addition to the increased flexibility achieved by increasing the share of 

gas-fired generation, Xcel Energy Colorado is also studying the ability of the natural gas storage 

and the delivery system to supply fuel to gas-fired generation resources which shoulder the 

majority of the 30-minute wind reserve duty. It has been identified that if an extreme wind ramp 

down event were compounded by the loss of a large coal unit, there may be the need to fuel 

switch some of the gas generation to fuel oil, especially during the beginning and end of the 

heating season, or electric load shoulder months, when storage injection or withdrawal rates of 

gas are at their lowest and wind generation is at its highest. 

Xcel Energy Colorado also applied changes to its Cabin Creek pumped Storage plant, including 

receiving WECC approval for Cabin Creek capacity to count toward spinning reserve, and 

 

66 Ibid. 
26 | brattle.com

shifting black start responsibilities away from Cabin Creek to other units to free up water that 

was otherwise reserved for black start for peak shaving and/or ancillary services. 

In 2011, Xcel Energy Colorado installed Automatic Generation Control (AGC) systems at four 

wind facilities in Colorado to enable the system operator to ramp down the output from these 

wind facilities automatically during certain periods.67 Today, two-thirds of the wind turbines in 

Xcel Energy Colorado are equipped with AGC and provide regulation. Furthermore, 

advancements in power electronics have enabled operators to provide frequency control through 

wind plants by extracting stored inertial energy from the wind turbines. The response time of 

these wind turbines that occur during the first ten-to-fifteen seconds following a large frequency 

dip is faster than the traditional governor response of larger conventional thermal generation 

resources and has proved to actually improve system performance. 

Finally, in late 2014 Xcel Energy Colorado filed a revised tariff to reflect a Joint Dispatch 

Agreement (JDA) with Platte River Power Authority and Black Hills Colorado Electric Utility 

Company. The JDA, with a framework similar to an energy imbalance market, although smaller 

in scale, is intended to provide the participating parties with a centralized, coordinated, intrahour dispatch system for their generation resources. The overall goal is to achieve more efficient 

and lower generation cost to serve load and is particularly helpful with increasing renewables 

penetration since variations of actual output from wind and solar generation compared to 

forecasts can be balanced across a larger set of resources.

68

VI. Other Innovative Approaches to Integrating Renewables 

Beyond the changes implemented by ERCOT and Xcel Energy Colorado, system operators and in 

some cases other market participants have implemented or are implementing a number of 

measures directly designed to facilitate the integration of larger amounts of variable renewable 

generation or having the side effect of doing so. In many instances, the changes do not require 

new technology, but it is also true that technological progress facilitates new approaches and in 

some cases creates entirely new opportunities. In this section we provide a brief summary of a 

sample of approaches and developments. In general, these approaches and developments follow 

 

67 Keith Parks, Wind and Solar Integration in Colorado: Challenges and Solutions, Xcel Energy, August 

9, 2011. 

68 Under the JDA, Energy transfers will be limited to average transmission capacity (ATC) between the 

participating systems at designated interconnection points. Unused ATC will be determined every five 

minutes after all other procurement and scheduling deadlines have passed. While the schedule-driven 

ATC updates currently occur every quarter-hour, the five-minute update ensures that any intra-hour 

schedule changes are adequately captured and that only the leftover ATC will be utilized through the 

JDA. The JDA will facilitate a joint economic dispatch of committed resources of the participants 

(determined at the beginning of the hour) and would likely reduce the curtailment of renewables and 

lower the overall production cost of the participating parties. 
27 | brattle.com

what was illustrated in the two cases studies: operational changes, such as shorter dispatch cycles; 

forecast enhancements; ancillary service changes; and transmission planning. 

As the case studies of ERCOT and Xcel Energy Colorado demonstrate, shorter dispatch cycles in 

combination with more accurate shorter-term forecasts of renewable generation are now 

commonly recognized as reducing forecast variations from renewable generators and leading to 

reduced ancillary service requirements. MISO (and SPP) are taking this concept one step further 

and dispatching wind resources similar to traditional generators, by asking the renewable 

resources to submit an offer curve for its generation quantity and price. The offer curve will be 

treated equally with other offer curves provided by traditional generators and be automatically 

dispatched based on merit order. The only difference is the generation quantity that can be 

offered by renewable resources depends on the wind forecast, rather than its physical plant 

capacity. MISO, by including 80% of its wind capacity in the 5 minute dispatch as Dispatchable 

Intermittent Resources,69 improved system reliability “through better congestion management by 

replacing manual curtailments with automated real-time dispatch.” 70 

MISO has also started developing and partially implementing a look-ahead unit commitment and 

dispatch process.71 The look-ahead process will focus on predicting near-term changes needed to 

keep energy flowing efficiently and cost-effectively. By incorporating forecast data for both load 

and renewable resources, it allows for better decision making, taking into account the likely 

future changes of the system (such as a ramping event that could result in local resource needs), 

rather than just considering the current status. Stochastic unit commitment, while still in its 

infancy, has been gaining traction as another tool for dealing with uncertainty.72 

Many system operators other than ERCOT and Xcel Energy Colorado have recognized the 

importance of forecasts and have developed and implemented customized centralized wind 

 

69 See MISO, MISO 2013-2014 Winter Assessment Report, Information Delivery and Market Analysis, 

June 2014, page 10. 

70 Minnesota Department of Energy Resources, Minnesota Renewable Energy Integration and 

Transmission Study, September 13, 2013, p. 21. Available at: http://mn.gov/commerce/energy/images/ 

MN_RE_Integration_Study_2014_pres_Stakeholder_Mtg_091313.pdf. The study notes that two-thirds 

of curtailments in MISO occur through the economic dispatch with the other third occurring still 

from manual curtailments. 

71 See MISO press release discussing how look-ahead tool improves efficiencies while reducing costs, 

available at: https://www.misoenergy.org/AboutUs/MediaCenter/PressReleases/Pages/Look-Ahead 

Tool.aspx. Further materials for the look-ahead tools are available at: https://www.miso 

energy.org/WhatWeDo/MarketEnhancements/Pages/LookAhead.aspx. 

72 For examples of stochastic unit commitment studies, see presentation from NREL and EPRI at: 

http://uvig.org/wp-content/uploads/2014/10/Ela-Stochastic.pdf and http://uvig.org/wp-content /uploads/ 

2014/10/Tuohy.pdf. 
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forecasts over the past few years.73 The forecasts used for commitment and dispatch decisions are 

also shared with various market participants. Forecast periods range from longer terms (typically 

up to a week-ahead) to a more granular short-term, updated frequently (every 5 to 15 minutes) 

and typically used for real-time operation decisions. PJM, ERCOT, and IESO also provide wind 

ramp forecasts. Solar forecasts are currently being developed in most markets.74 

Several system operators are now allowing wind to provide ancillary services. Both PJM and 

NYISO allow wind to provide frequency response, inertial response, and regulation if they meet 

eligibility requirements. While ISO-NE precludes wind from providing regulation, it does allow 

wind to provide frequency response and inertial response upon meeting eligibility requirements. 

SPP allows variable resources to provide regulation down if they meet eligibility requirements. 

Ancillary service markets are also evolving to provide incentives for faster responding resources 

that can provide better performance. For example, in response to a FERC order, PJM provides 

“mileage payments,” which account for how well resources respond to the regulation signal for 

controlling frequency.75 

Transmission planning, as the ERCOT CREZ line success demonstrates, is also a key focus of 

system operators. MISO, through its Regional Generation Outlet Study (RGOS), created a 

cohesive plan for the MISO footprint by identifying extended transmission plans and renewable 

energy requirements. The RGOS results were later adopted as the Multi-Value projects. Similarly 

the SPP Integrated Transmission Planning process coordinates the long term transmission 

planning with anticipated future resources, a large portion of which is wind. 

In addition to these enhancements of traditional tools and processes, storage technologies are 

beginning to be tested, included in ancillary service eligibility, or deployed. PJM’s frequency 

regulation market, which in response to FERC’s Order 755 76 awards quick-start and fastresponding resources including batteries, has been attracting an increasing amount of battery 

storage.77 Along with storage technology, innovation is occurring in ways of using storage. Much 

of this innovation is targeting opportunities created by the mismatch of variable renewable 

 

73 Centralized wind forecasts have been implemented in the various markets: PJM (2009), NYISO (2008, 

used for individual dispatch decisions since 2009), ISO-NE (2014), MISO (2008), SPP (201), ERCOT 

(2008), CAISO (2004), AESO (2010), and IESO (2013). 

74 Centralized solar forecasts are only implemented in limited markets: IESO (2013) and ERCOT (2015). 

75 See http://www.pjm.com/markets-and-operations/ancillary-services/mkt-based-regulation/fastresponse-regulation-signal.aspx 

76 See Beacon Power, Overview of FERC Order 755 and Pay-for-Performance Regulation, March 21, 

2014 for an overview of compensation for frequency regulation before and after FERC Order 755. 

77 See http://www.utilitydive.com/news/invenergy-bringing-over-60-mw-of-storage-online-for-pjm-frequ 

ency-regulatio/399140/. According to the article, Invenergy recently announced the addition of 31.5 

MW of storage at its Grand Ridge Storage Facility in Illinois to provide frequency regulation in PJM. 

Invenergy plans to bring another 31.5 MW storage facility online in 2015, bringing the total storage 

capacity providing frequency regulation services in PJM to above 150 MW. 
29 | brattle.com

generation and demand. For example, the recent launch of Tesla’s home battery system happened 

approximately at the same time as the announcement of a collaboration between Tesla and 

Lichtblick, a German company. Lichtblick has been using its proprietary aggregation software to 

bundle an increasing number of micro-combined heat and power systems deployed in residential 

buildings and deploy them as “swarm” energy producers,78 optimizing the operation of many 

distributed systems – most of which have a thermal storage element – against real-time power 

market conditions. The joint venture between Tesla and Lichtblick aims to combine distributed 

solar PV systems with in-home storage units and Lichtblick’s optimization software to similarly 

operate solar+battery systems in a way that optimizes their use given real-time market conditions 

by taking advantage of the latent flexibility in distributed energy systems.79

There are also ongoing innovations combining variable renewable production with measures 

aiming to make demand more responsive. Tesla is also collaborating with EnerNOC, a leading 

provider of demand response services for commercial and industrial customers.80 Also, earlier in 

2015 SolarCity, a major installer of rooftop solar PV systems, announced a partnership with 

NEST, the wifi-enabled (smart) thermostat company owned by Google.81 While still in early 

stages, a French start-up, Comwatt, has developed a box, similar to a cable TV box, that uses 

software to manage electricity consumption in a house to match as much as possible the 

production of a distributed solar PV system.82 All these recent announcements show not so much 

what is already happening in terms of actively integrating variable renewable energy, but the 

extent to which integration associated with increases in renewable energy production is 

stimulating innovation. 

By the time renewable penetration levels approach those currently identified as practical limits, 

it is likely that at least some of these innovations will have matured enough to play a role in 

providing solutions, thus quite likely further increasing the share of variable renewable energy 

that can safely be integrated into the grid. 

 

78 See http://www.lichtblick.de/en/schwarmenergie/. 

79 See http://www.prnewswire.com/news-releases/partnership-for-global-energy-transformationlichtblick 

-integrates-tesla-battery-storage-into-energy-markets-502146711.html

80 See http://www.bidnessetc.com/41612-tesla-motors-inc-collaborates-with-enernoc-inc-and-lichtblickfor -energy-st/. 

81 See http://www.solarcity.com/newsroom/press/solarcity-and-nest-partner-make-cost-savings-eveneasier-homeowners. 

82 See http://www.cleantechrepublic.com/2014/12/18/comwatt-autoconsommation-electrique-sansbatterie/ (in French). 
30 | brattle.com

VII. Conclusions 

In this report, we highlighted how a few ISOs and utilities with material shares of renewable 

generation already have changed their operations to accommodate the forecasting challenges and 

short-term performance variability that can increase with growing shares of variable renewable 

generation. To date, these integration efforts have been largely relying on well-established 

technologies, indicating that lack of technology cannot be considered a major barrier to being 

able to integrate amounts of variable renewable generation significantly in excess of current 

average U.S. levels. Though new technologies are being explored and becoming more promising, 

particularly storage, it is not necessary to have large amounts of such new resources to 

incorporate meaningful quantities of renewables onto a system and preserve its security and 

reliability. 

As these case studies show, ISOs and utilities can deploy a large and increasing portfolio of 

options to accommodate large and growing shares of renewable generation while maintaining 

high levels of reliability. The options range from purely operational changes to possibilities that 

become available as a consequence of advancements in technology unrelated to renewable 

energy. Examples of the former include increasing the coordination between balancing areas 

(including increasing their size), reinforcing the transmission system, and increasing 

participation of demand response. Examples of the latter include technological advances in 

weather forecasting which, together with better data on historical performance of renewable 

energy, allows significant improvements in forecasting accuracy of renewable generation; the 

proliferation of smarter infrastructure, much of it deployed at the customer site (smart meters, 

smart thermostats, smart appliances, all enabled by smarter software), enabling participation of 

increasing amounts of demand in activities that help mitigate the variability of renewable 

generation; and technological advances of renewable and complementary technologies 

(inverters, batteries) that allow renewable generators themselves to contribute to maintaining 

reliability. 

Numerous renewable integration studies have estimated the cost of using this wide portfolio of 

options to represent a relatively small portion of the overall cost of the electric system. Our case 

studies indicate that deploying new and innovative solutions can further mitigate the challenges 

of integrating variable renewable generation, at least in some cases (such as using state-of-the-art 

wind and solar forecasts) with significant cost savings compared to traditionally used integration 

approaches. Continued strong growth of renewable generation will require continued significant 

planning and effort, as well as investment in the electric infrastructure – in transmission 

infrastructure to bring electricity from renewable resource rich locations to load centers, and in 

distribution infrastructure as the share of distributed resources grows. Bringing additional 

renewable resources to market will thus likely be an important additional driver of planning and 

building a 21st century grid, which is also driven by changes on the demand side of the market 

(including distributed generation, but also new sources of demand and options for demand-side 

flexibility), changing population densities, the desire to further increase inter-regional 

interconnections, cybersecurity concerns, the aging of existing transmission and distribution 

infrastructure, etc. 
31 | brattle.com

The good news, however, is that there is substantial evidence that accommodating these 

increasing levels of variable renewable generation in ways that preserve high levels of reliability 

should be possible at a cost (excluding the cost of any incremental transmission) that represents a 

modest share of the total cost of the electric system. Specifically, integration of variable 

renewable energy at levels of penetration as high as those reliably managed by ERCOT and Xcel 

Energy Colorado, if not higher, should not be seen as a significant obstacle to compliance with 

EPA’s proposed Clean Power Plan. 

 
32 | brattle.com

VIII.Acronyms 

AEEI Advanced Energy Economy Institute 

AGC Automatic Generation Control 

ALR Adaptive Line Ratings 

BSER Best System of Emissions Reductions 

CHP Combined Heat and Power 

CNG Compressed Natural Gas 

CO2 Carbon Dioxide 

CPP Clean Power Plan 

CREZ Competitive Renewable Energy Zone 

DLC Direct Load Control 

DLR Dynamic Line Ratings 

DR Demand Response 

EE Energy Efficiency 

ELCC Effective Load Carrying Capability 

EPA Environmental Protection Agency 

ERCOT Electric Reliability Council of Texas 

ERS Emergency Response Service 

FAS Future Ancillary Services 

FFR Fast Frequency Response 

GW Gigawatt 

HVDC High Voltage Direct Current 

IRR Initial Reliability Review 

ISO Independent System Operator 

JDA Joint Dispatch Agreement 
33 | brattle.com

LMP Locational Marginal Price 

MISO Midcontinent ISO 

MW Megawatt 

NERC North American Electric Reliability Corporation 

PSCo Public Service Company of Colorado 

PV Photovoltaic 

RGOS Regional Generation Outlet Study 

RTO Regional Transmission Organization 

SPP Southwest Power Pool 

T&D Transmission and Distribution 

U.S. United States 
34 | brattle.com

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36 | brattle.com

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