Northwest

Wind Integration

Action Plan

March 2007

Pre-publication version

Wind Integration Forum

document 2007-1
Northwest Wind Integration Action Plan

Policy Steering Committee 

March 2007 

Dear Interested Party: 

 

It has been eight months since we began addressing the challenge of how to best integrate 

wind energy into the Pacific Northwest’s existing hydro-rich electricity system. The 

attached Northwest Wind Integration Action Plan is the result of the hard work and 

collaboration of many of the region’s utility, regulatory, consumer, and environmental 

specialists. The report has several important policy findings and conclusions: 

1) There are no fundamental technical barriers to operating 6,000 megawatts of 

wind in the Pacific Northwest. 

There is a range of estimated costs associated with integrating wind into the Northwest 

power system. When wind energy is added to a utility system, its natural variability and 

uncertainty is combined with the natural variability and uncertainty of loads. As a result, 

there is an increase in the need for system flexibility required to maintain utility system 

balance and reliability. The cost of wind integration starts low, particularly when 

integrating with a hydropower system that has substantial flexibility, and then rises as 

increasing amounts of wind are added. Locating wind resource in geographically diverse 

areas can help reduce costs. Ultimately, costs plateau at the cost of integrating wind with 

natural gas power plants. 

 

The preliminary cost estimates for integrating 6000 MW of wind power are based upon 

existing levels of system flexibility. Load growth and other competing uses for that 

flexibility, and possible further constraints on system operations will diminish the supply 

and increase the cost of wind integration services. 

With increasing amounts of wind, there will likely be times when large, unexpected 

changes in wind output (so-called “ramping events”) coincide with periods of limited 

hydro flexibility. Initial analyses indicate that these will be low probability events, but if 

other sources of flexibility are not available at the same time, system operators will need 

to limit wind output for brief periods in order to maintain reliability. The Federal Energy 

Regulatory Commission now requires wind plant operators to help protect system 

reliability. Northwest utilities and wind developers are collaborating to implement the 

requirement in a mutually-satisfactory and cost-effective manner. 

2) Wind energy is providing value to Northwest electricity consumers, but the 

Northwest will still need other resources to meet peak loads. 

The fundamental value of wind to a utility’s portfolio is its ability to provide energy to 

displace fossil fuel consumption, limit exposure to uncertain and volatile fuel prices, and 

hedge against greenhouse gas control costs. Because wind is primarily an energy 

resource with relatively little contribution to meeting system peak requirements, the 

Northwest will need to build other resources with greater capacity value to meet growing 

peak loads. 
 

3) In the short term there is available transmission capacity to integrate additional 

wind resources – but this is not expected to last for long. 

New transmission will be needed to support growing loads and resource additions and 

can help open up new areas for wind development, helping to diversify wind production. 

This diversity helps smooth variability and therefore lowers the cost of wind integration. 

Because of the limited contribution of wind to meeting system peak requirements, 

traditional models for transmission development and marketing should be altered to 

achieve greater economic efficiency. A more economical and efficient approach for a 

resource such as wind is to provide a mix of firm, non-firm, and conditional firm 

transmission that achieves a balance between the cost of transmission capacity and the 

value of delivered wind energy. Cooperation among transmission planners, regulators, 

utilities, and the wind development community is essential to create a workable model for 

planning, financing, and marketing transmission for wind energy. 

 

4) The major portion of wind integration costs are due to the need for additional 

flexibility resources to balance loads and resources in real time in order to 

accommodate wind variability. 

Control area operators must have sufficient flexible generating capacity or load 

management options available to accommodate load and wind variability to ensure that 

reliable service will be maintained. There should also be provisions for equitable 

recovery of the associated costs. 

 

5) There are steps we can take to increase integration capability and to lower 

integration costs. 

The cost of wind integration services can be reduced through generally four types of 

actions: (1) developing more cooperation between regional utilities to spread the 

variability of wind more broadly; (2) developing markets that will reward entities who 

choose to market their surplus flexibility; (3) making more low-cost flexibility such as 

that provided by hydroelectric resources available; and (4) development and application 

of new flexibility technologies. Achieving these goals will require coordinated actions 

similar to those required to establish the Pacific Northwest Coordination Agreement of 

the Columbia River Treaty. Fortunately, the region has a long history of forging 

cooperative agreements designed to increase the size of the pie for all regional consumers 

that can provide a model for what will be needed over the next several years to address 

wind integration issues. 

Sincerely, 

 Tom Karier Stephen J. Wright 

Chair Administrator and CEO 

Northwest Power and Conservation Council Bonneville Power Administration 

Co-Chair, Policy Steering Committee Co-Chair, Policy Steering Committee 
Northwest Wind Integration 

Action Plan 

March 2007 

Copies of this report are available from the Northwest Power and Conservation Council, 851 SW Sixth Avenue, Suite 1100, 

Portland, Oregon 97204; 503-222-5161; www.nwcouncil.org 

Cover Photo: Klondike II wind project. Photo courtesy of Leon Werdinger (www.ottertrack.com) 
Participating organizations and individuals

Steering Committee 

Tom Karier, Northwest Power and Conservation Council, Co-Chair 

Stephen J. Wright, Bonneville Power Administration (BPA), Co-Chair 

Walt Pollock, Facilitator 

 

Jorge Carrasco, Seattle City Light 

Teresa Conway, Powerex 

Tim Culbertson, Grant County PUD 

Bill Drummond, Western Montana G&T 

Angus Duncan, Bonneville Environmental Foundation

David Gates, NorthWestern Energy

Terry Hudgens, PPM Energy

Greg Jergeson, Montana Public Service Commission 

Jim Kempton, Northwest Power and Conservation Council 

Paul Kjellander, Idaho Public Utility Commission 

Jim Lobdell, PGE 

Eric Markell, Puget Sound Energy

Louise McCarren, WECC 

Jim Miller, Idaho Power 

Kelly Norwood, Avista 

John Prescott, PNGC Power 

John Savage, Oregon Public Utility Commission 

Rachel Shimshak, Renewable Northwest Project 

Marilyn Showalter, Public Power Council 

Brian Skeahan, Cowlitz PUD 

Stan Watters, PacifiCorp 

Technical Work Group 

Jeff King, Northwest Power and Conservation Council, Co-Project Manager 

Elliot Mainzer, BPA, Co-Project Manager 

Frank Afranji, PGE 

John Apperson, PacifiCorp 

Philip Augustin, PGE 

Jamie Austin, PacifiCorp 

Bryan Baldwin, Montana Public Service Commission 

Steve Barton, BPA 

Rebecca Berdahl, BPA 

Sarah Bermejo, BPA 

Karl Bokenkamp, Idaho Power 

Lowrey Brown, Citizens’ Utility Board of Oregon 

Stefan Brown, Oregon Public Utilities Commission

Ray Brush, NorthWestern Energy 

Grant Brohm, WindLogics 

Ron Brzezinski, General Electric 

Phil Carver, Oregon Department of Energy 

2
Kevin Conway, Grant County PUD 

Carel DeWinkel, Oregon Department of Energy 

Robert Dies, CDD Howard 

Bo Downen, Public Power Council 

Ken Dragoon, Renewable Northwest Project 

Jim Eden, PGE 

Steve Enyeart, BPA 

Doug Faulkner, Puget Sound Energy

Larry Felton, Energy Northwest 

David Fine, NorthWestern Energy

Bruce Folsom, Avista 

Thomas Fung, British Columbia Transmission Corporation 

David Gilman, BPA 

Kurt Granat, PacifiCorp 

Roger Hamilton, Wind on the Wires 

Mike Heckler, Windland, Inc. 

Joe Hoerner, Puget Sound Energy 

Mike Hoffman, BPA 

Pamela Jacklin, Stoel Rives 

Mark Jackson, BPA 

Mike Jacobs, American Wind Energy Association 

Casey Johnston, NorthWestern Energy

Hardev Juj, Seattle City Light 

Clint Kalich, Avista 

Mike Kelly, Horizon Wind Energy

Brendan Kirby, Oak Ridge National Laboratory

Mark Lively, Lively Utility 

Diane Lozovoy, PacifiCorp 

Gordon Dobson-Mack, Powerex 

Yuri Makarov, Pacific Northwest National Laboratory 

John Martinsen, Snohomish PUD 

Chuck Matthews, BPA 

Jack Mayson, Regulatory & Cogeneration Services 

Natalie McIntire, Renewable Northwest Project 

Bart McManus, BPA 

Jeff Miller, PacifiCorp 

Michael Milligan, National Renewable Energy Laboratory 

James Murphy, BPA 

Tom Murphy, BPA 

Irena Netik, Puget Sound Energy

Huyen Nguyen, Puget Sound Energy

Kevin Nordt, Grant County PUD 

Rod Noteboom, Grant County PUD 

Dan O’Hearn, Powerex 

Brian Parsons, National Renewable Energy Laboratory

Bill Pascoe, Pascoe Energy

John Pease, BPA 

Lon Peters, Northwest Economic Research, Inc. 

Chris Reese, Puget Sound Energy 

Mike Ryan, PGE 

Irion Sanger, Industrial Customers of Northwest Utilities 

3
Steve Saylors, Vestas 

Howard Schwartz, Northwest Power and Conservation Council 

Joe Seabrook, Puget Sound Energy

Paul Schmidt, SPPC 

Marilynn Semro, Seattle City Light 

Brian Silverstein, BPA 

Charlie Smith, Utility Wind Integration Group 

Mark Smith, FPL Energy

Steve St. Clair, Puget Sound Energy

Rick Sterling, Idaho Public Utilities Commission 

Pascal Storck, 3 TIER 

Jaison Tsikirai, PacifiCorp 

Chris Turner, Seattle City Light 

Scott Waples, Avista 

Mark Widmer, PacifiCorp 

Editor: Deston Nokes, BPA 

4
Table of contents 

Introduction and executive summary ........................................................................................... 6 

I. The role of wind energy in the Northwest power system....................................................... 15 

II. Operational capability and costs of integrating wind in the Northwest ................................ 28 

III. Transmission requirements for integrating 6,000 megawatts of Wind ................................ 36 

IV. Wind integration cost recovery............................................................................................ 40 

V. Regional efforts to reduce integration costs.......................................................................... 42 

VI. Complete list of Action Plan items...................................................................................... 48 

Glossary...................................................................................................................................... 50 

Appendix A. The language of Northwest utility system operations............................................ 1 

Appendix B. Discussion of study methodologies and preliminary results from initial Northwest 

wind integration studies ............................................................................................................... 1 

Appendix C. Technical requirements and cost estimate for development of a Northwest 

chronological wind data set.......................................................................................................... 1 

Appendix D. Other supply and demand-side flexibility technologies......................................... 1 

5
Introduction and executive summary 

Overview 

The Pacific Northwest, already blessed with abundant hydroelectricity, is now seeing rapid 

growth in another of its renewable energy resources – wind power. 

Less than a decade after the region’s first commercial-scale wind project came online in 1998 

(the 25-megawatt Vancycle project in Eastern Oregon), nearly 1,400 megawatts (MW) of wind 

generation have connected to the grid. Over the next three years, as much as 2,400 MW of 

wind power is expected to come on line in the region, for a total of nearly 3,800 MW by 2009. 

The Northwest Power and Conservation Council’s Fifth Northwest Electric Power and 

Conservation Plan (Fifth Power Plan) includes up to 6,000 MW of developable and potentially 

cost-effective wind power. The Fifth Power Plan also calls for the development of a wind 

confirmation plan to resolve uncertainties surrounding wind power development. This Action 

Plan serves that purpose. 

Many factors are driving wind energy’s growth, including volatile natural gas prices, and 

renewable energy and climate policy developments at the federal, state and local levels. 

Among recent developments: 

• Western governors have called for 30,000 MW of clean, diversified energy in the 

Western Interconnection by 2015. 

• Montana adopted a renewable portfolio standard of 15 percent by 2015. 

• Washington’s electorate adopted Initiative 937, mandating a 15 percent renewable 

portfolio standard for the majority of load in the state by 2020. 

• The Oregon Governor’s Renewable Energy Task Force has recommended that Oregon 

adopt a renewable portfolio standard of 25 percent by 2025. 

• The federal Wind Energy Production Tax Credit has been extended through 2008. 

Clearly, wind energy is going to play a major role in the future of the Northwest power system. 

Through this Northwest Wind Integration Action Plan (Action Plan), many of the region’s 

utility, regulatory, consumer, and environmental organizations have worked together to address 

several major questions surrounding the growth of wind energy. These include: 

• What is the role of wind energy in a power supply portfolio and how does it impact 

system operations? 

• Does the Pacific Northwest have the operational capability to integrate 6,000 MW of 

wind? If so, what are the estimated costs of integrating this amount of wind energy? 

• What are the transmission requirements for developing 6,000 MW of wind? 

• How will the costs of wind integration be recovered? 

6
• How can we work together to help the Northwest meet its wind energy potential in the 

most cost-effective manner? 

This effort has produced significant findings regarding the ability of the Northwest to accommodate 

future wind power development. The effort has also identified issues that need to be resolved for wind 

power to achieve its full potential. This Action Plan recommends 16 actions intended to help resolve 

these issues. Of particular importance are actions addressing challenges associated with transmission 

marketing, planning and expansion, and the limited market for control area services. A final action 

calls for the formation of a Northwest Wind Integration Forum to facilitate implementation of the 

Action Plan. Below is a summary of the major findings and action items.

The role of wind energy in a power supply portfolio

The fundamental value of wind power to a utility portfolio lies in its ability to displace fossil 

fuel consumption, limit exposure to volatile fossil fuel prices, and hedge against possible 

greenhouse gas control costs. 

Wind is primarily an energy resource that makes relatively little contribution to meeting system

peak loads. Even with large amounts of wind, the Northwest will still need to build other 

generating resources to meet growing peak load requirements. Wind energy is a renewable, 

clean energy resource that will lower the fuel consumption and environmental emissions of

other resources. But wind energy cannot provide reliable electric service on its own. 

When wind energy is added to a utility system, its natural variability and uncertainty is 

combined with the natural variability and uncertainty of loads. This increases the need for 

flexible resources such as hydro, gas-fired power plants, or dispatchable loads to maintain 

utility system balance and reliability across several different timescales. The demand for this 

flexibility increases with the amount of wind in the system. 

Operational capability and costs of integrating wind in the Northwest

Initial wind integration studies by Avista, Idaho Power, BPA, Puget Sound Energy and 

PacifiCorp find no fundamental technical barriers to achieving the Council’s target of 6,000 

MW of wind. It’s a question of cost. 

Conceptually, the cost of wind integration starts low, as the amount of variability introduced by 

a small amount of wind is virtually lost in the larger fluctuations of loads. As the amount of 

wind increases, the effects of wind variability dominate the effects of load variability, and 

flexibility needs to be added to the system in direct proportion to the growing wind penetration. 

Access to large amounts of existing system flexibility, such as that provided by the region’s 

hydroelectric resources, can help minimize the costs of wind integration and postpone the need 

for investments in other sources of system flexibility. Costs ultimately plateau at the cost of

procuring system flexibility from natural gas-fired power plants. 

Preliminary cost estimates from the initial Northwest wind integration studies are cited below. 

The studies represent a significant step forward in regional understanding of wind integration 

costs, but it should be carefully noted that the cost figures and methodologies underlying the 

studies are still the subject of debate among members of the Technical Work Group who 

7
worked on this document. Revisions to several of the studies are still under way. All of the 

utilities reporting results intend to revisit their study methodologies and results as better data 

and analytical techniques become available. 

The cost estimates will eventually be translated into formal rates and/or market prices that may 

deviate from the numbers cited below. The cost estimates are also based on current system

obligations and constraints that are subject to change. Future reductions in system flexibility 

could result in higher costs. The costs may also come down as a result of ongoing study 

revisions, greater control area coordination, or other cost-reduction strategies. 

The most current, officially released study results are posted on the Council’s Website at 

www.nwcouncil.org/energy/Wind and will be updated on a regular basis. 

The Avista, Idaho Power, Puget and PacifiCorp studies evaluated both the within-hour and 

hour-to-hour costs of integrating wind for native load service. The BPA study was initially 

limited to within-hour costs in order to inform tariff and rate revisions that will be required to 

recover the costs of integrating wind projects serving nonfederal loads. As a result, the BPA 

integration cost estimates are shown separately and likely represent a low-end estimate for the 

BPA system, as the federal agency has yet to formally assess hour-to-hour costs. 

Table 1: Preliminary wind integration costs from investor-owned utility studies of wind 

generation at various levels of wind penetration12 ($/MWh of wind generation) 

Utility Peak Load (MW) 5% 10% 20% 30%

Avista 2,200 $2.75 $6.99 $6.65 $8.84

Idaho Power 3,100 $9.75 $11.72 $16.16

Puget Sound Energy 4,650 $3.73 $4.06

PacifiCorp 9,400 $1.86 $3.19 $5.94

 

Table 2: Preliminary wind integration costs from BPA study of wind generation at various 

levels of wind penetration ($/MWh of wind generation)

Utility Peak Load (MW) 5% 10% 20% 30%

BPA (Within-Hour Impacts Only) 9,090 $1.90 $2.40 $3.70 $4.60

Based on Northwest studies and others from around the world, the cost of wind integration is 

largely dependent on: (1) the size of the control area from which such services are procured in 

relation to the amount of wind being integrated; (2) the geographic diversity3

 of wind sites and 

resultant generation patterns; (3) the amount of flexibility available to the power system, and 

(4) access to robust markets for control area services and storage and shaping products. 

With increasing amounts of wind, there likely will be times when large, unexpected changes in 

wind output (“ramping events”) coincide with periods of limited system flexibility. Initial 

 1

 Penetration is defined as installed wind divided by peak load. 2

 The Avista 20% and 30% penetration figures assume a much larger geographic footprint than its 5% and 10% 

scenarios. The benefits of geographic diversity are apparent in that a doubling of wind generation comes at a 

lower cost than the less-diversified 10% case. As the 20% and 30% penetration cases assume the same wind plant 

geography, integration costs rise from 20% to 30%. 3

 Diversity in this context refers to the extent to which changes in wind output at one wind site are different from

the changes at other wind sites. 

8
analyses indicate that these will be low-probability events, but in some instances, system

operators will need to limit wind output for brief periods in order to maintain system reliability. 

The Federal Energy Regulatory Commission now requires wind plants to help protect system

reliability. Northwest utilities and developers are collaborating to implement this requirement 

in a mutually satisfactory and cost-effective manner. 

Wind integration studies have been performed on a variety of systems and wind penetration 

levels both within and outside the United States. Care must be taken when comparing these 

studies because of differences in regional market structures and other variables. In general, the 

studies have found that wind integration costs are a significant, but not dominating portion of 

total wind resource costs, up to wind nameplate penetration levels of 20 to 30 percent of peak 

load. In addition to wind integration costs, a full economic assessment of the value of wind 

energy to a utility portfolio must consider other variables. These include the daily and seasonal 

pattern of wind generation, the busbar price and environmental emissions of wind compared to 

other generating resources, the costs of transmission, and the benefits of a relatively fixed-price 

resource with no exposure to carbon legislation. 

The Northwest does not possess wind data adequate to quantify the benefits of cooperative 

operational strategies, to evaluate the benefits of geographical diversification, to inform 

transmission planning efforts, and to fully evaluate the capacity value of wind. A multiyear, 

high-resolution, synthetic data set should be developed to support these analyses. 

Transmission requirements for integrating 6,000 MW of wind 

The amount of transmission capacity that is currently available to Northwest wind projects is 

only sufficient to support anticipated development through 2009. Additional transmission 

capacity will be needed to achieve the 6,000 MW of wind envisioned in the Council’s plan and 

to open up new areas for wind development that will diversify wind production. This diversity 

can reduce total variability and therefore lower the cost of wind integration on a $/MWh 

basis. It can also provide access to higher capacity factor wind resources, which can lower the 

busbar costs of wind generation. 

While firm transmission is necessary to secure the capacity value of a conventional generating 

plant, the economically optimal approach for a variable resource with limited capacity value 

like wind is to seek a mix of firm, nonfirm or conditional firm transmission that balances the 

marginal cost of transmission and the marginal value of delivered wind energy. Achieving this 

balance will require a combination of transmission expansion, new commercial practices and 

new regulatory policies. It may also require reallocation of risk and compensation between 

project owners and purchasing utilities to enable wind project financing. 

Increasing congestion in key sections of the Northwest transmission network, including the 

West of McNary Corridor, the I-5 Corridor, the North Cross-Cascades Corridor and South 

Cross-Cascades Corridor suggests that steps to prepare for eventual construction of these 

projects are prudent. Plans of service and business case assessments should be completed for 

each. Environmental assessment and other preconstruction activities would follow a favorable 

business case in order to secure at least the option to build the lines. Studies should be 

9
undertaken to evaluate the costs and benefits of extending transmission capacity to Montana 

and other prime wind resource areas. 

Products and strategies that make better use of existing transmission lines, such as conditional 

firm and voluntary economic redispatch, may enable new wind projects to come on line before 

new transmission lines are constructed, or extend the time until transmission construction is 

required. A pilot voluntary economic redispatch program with the initial objective of using 

existing West of McNary transmission as effectively as possible should be developed and 

tested. 

Eventual construction of new transmission will require a financing model for projects that are 

largely driven by new generation development. The financing model must address the Catch-22 

confronting many wind project developers: they cannot make financial contributions to a new 

transmission line unless they have security in the form of a power purchase agreement; yet they 

typically cannot secure a power purchase agreement without a long-term transmission service 

agreement. 

BPA is working with regional stakeholders to develop a generally applicable approach for 

financing and recovering the costs of partly or wholly market-driven transmission projects 

using West of McNary as a prototype. Ideally, the approach would also be applicable to 

renewable trunk line transmission. 

Wind integration cost recovery 

Current tariff and rate provisions may not be sufficient to recover the costs of wind integration 

in all cases. Cost recovery and allocation is a threshold issue for each control area and there are 

diverse opinions about the point at which these costs warrant developing a new tariff, and how 

that tariff should be designed and applied. All seem to agree that there should be a defensible 

basis for determining any additional costs resulting from wind resources interconnecting in a 

control area. 

The cost threshold has been reached at BPA. By the end of 2007, BPA may have as much as 

1,500 MW of wind in its control area – much of it serving nonfederal loads. In 2007, BPA 

expects to revise its approach to recovering and allocating wind integration costs through 

formal rate case proceedings. Sales of wind integration services will not compromise BPA’s 

statutory obligations to its requirements customers. 

Regional efforts to reduce integration costs 

Coordination among utilities in the Northwest, in order to realize the benefits of a variable and 

relatively low capacity factor renewable resource, has a distinguished history in the Pacific 

Northwest. Both the Pacific Northwest Coordination Agreement (PNCA) and the Columbia 

River Treaty brought the benefits of hydro generation diversity and energy storage sharing to 

the region. Those benefits were used to help finance construction of the Pacific NW-SW

transmission intertie. Regional coordination of wind resources can net similar savings and 

benefits. 

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The cost of wind integration rises as the percentage of wind grows on the interconnected 

system. For example, integration costs of a 100 MW wind facility on a control area with a peak 

of 500 MW (20 percent penetration) is much higher than the same facility hosted by a 5,000 

MW control area (2 percent penetration). This cost differential is due to the fact that the larger 

control area already has enough flexibility to manage large load fluctuations. Short of actual 

control area consolidation, the two most significant steps toward realizing this benefit are the 

development of expanded wholesale markets for control area services and greater operating 

reserve sharing. If successful, these steps can help shift the existing wind integration supply 

curve to the right. 

Developing more robust markets for control area services will provide needed electric services 

for smaller control areas with substantial wind resources, such as NorthWestern Energy in 

Montana. Without access to such markets, development of otherwise cost-effective and diverse 

wind resources is at risk. Development of such markets can be accomplished within the 

framework of the Northwest’s current market structure. 

Building on existing contingency reserve sharing agreements, several Northwest utilities are 

participating in a pilot program to share Area Control Error (ACE) through the ACE Diversity 

Interchange project. Lessons learned from this effort may help solve some of the technical and 

institutional barriers to more robust markets for control area services and greater operating 

reserve sharing. 

Wind integration studies performed in the Northwest and other regions have concluded that the 

demand for operating reserves and resulting wind integration costs are very sensitive to wind 

forecast accuracy. The potential of a regional wind forecasting network to reduce wind

integration costs, and to provide added value to participating utilities and wind project 

operators, should be investigated. 

In the future, new technologies such as pumped storage, compressed air and demand 

management may play a greater role in providing system flexibility. However, at present, the 

principle alternative to hydro generation for providing system flexibility is natural gas-fired 

generation. In an increasingly carbon-constrained world, the tradeoffs between losses of 

hydrosystem flexibility and greater reliance on fossil-fired generation to integrate wind, need to 

be formally evaluated alongside other tradeoffs between competing uses of system flexibility. 

The Council can initiate this assessment through Action GEN-94

 of its Fifth Power Plan. In 

addition, future power plans should explicitly consider the tradeoffs between transmission 

 4

 Text of GEN-9 from Fifth Power Plan: 

ACTION GEN-9: The Council will assess the effects of shaping wind power on other functions of the 

hydropower system – A better understanding of the possible effects of shaping large amounts of wind capacity

on the hydropower system is essential to correctly valuing shaping services and to establishing possible 

operational limits on those services in order to avoid adversely affecting other hydropower system operations. The 

Council will take the lead in devising and conducting an assessment of these effects. Bonneville, the Corps of

Engineers, utilities having hydropower resources suitable for shaping wind energy, and other stakeholders are 

encouraged to participate in this assessment.

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investment, improved wind project performance through geographic diversification and the 

cost of flexibility augmentation options. 

12
Summary of Action Plan items 

A summary of the recommended actions follows. Additional detail regarding these 

recommendations is provided in Section VI of this report. 

 

1) The Northwest Resource Adequacy Forum should reassess its 15 percent pilot sustained 

wind capacity value. 

2) Northwest utilities should continue to refine their estimates of wind integration costs 

using a robust stakeholder process and develop estimates of potential cost reductions 

from control area cooperation, more active markets for control area services and other 

strategies. 

3) The Northwest Wind Integration Forum should contract for the development of a highresolution wind resource data set for the Pacific Northwest. 

4) The Northwest Transmission Assessment Committee (NTAC) should propose a formal 

technical transmission planning methodology that seeks a balance between the cost of 

transmission capacity and the value of delivered wind energy. 

5) Columbia Grid and the Northern Tier Transmission Group, together with NTAC, 

should begin applying the NTAC transmission planning methodology to regional 

transmission planning. 

6) The four state regulatory commissions should review and amend as necessary 

regulatory policies to remove barriers to more efficient use of transmission for wind and 

other renewable resources. 

7) BPA and other Northwest parties should explore ways to make more efficient use of 

existing transmission infrastructure, such as conditional firm transmission service and 

redispatch. 

8) BPA should complete plans of service and review the business cases for the proposed 

West of McNary, I-5 Corridor and Cross-Cascades transmission reinforcements. 

9) BPA should develop a general model for financing market-driven transmission 

improvements, using the proposed West of McNary project as a prototype. 

10) NTAC, building on the results of the Rocky Mountain Area Transmission Study 

(RMATS), should evaluate approaches to delivering wind energy from Montana such as 

an upgrade of the 500kV system in Montana, and evaluate opportunities to deliver wind 

energy from other isolated wind resource areas. 

11) The Northwest Wind Integration Forum should evaluate the costs and benefits of a 

regional wind forecasting network and, if positive, develop an implementation plan. 

12) The participants in the ACE Diversity Interchange pilot should provide a progress 

report to the Steering Committee of the Northwest Wind Integration Forum. 

13) The Northwest Wind Integration Forum should address barriers to expanding the 

market for control area services and wind integration products. 

13
14) The Northwest Wind Integration Forum should characterize options for augmenting 

system flexibility. The Northwest Power and Conservation Council (Council) should 

complete Action GEN-9 of its Fifth Power Plan to improve understanding of the 

tradeoffs between competing uses of system flexibility in an increasingly carbon 

constrained environment. 

15) The Council, in future power plans, should incorporate a planning framework to 

maximize the economic and environmental value of wind energy. 

16) The Council, working with BPA and other interested organizations, should establish a 

Northwest Wind Integration Forum to facilitate implementation of the actions called for 

in this Action Plan. 

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I. The role of wind energy in the Northwest power system 

Wind energy displaces fossil fuels and reduces exposure to price volatility 

Wind power is a zero-emission energy resource with no fuel costs. The primary benefits of 

wind energy are displacement of fossil fuels and their associated emissions and carbon dioxide 

production, and reduced exposure to natural gas price uncertainty and volatility. 

Southern California Edison, with 25 years of wind integration experience, explicitly refers to 

wind as a “fuel displacement resource.” Historically, utilities have added resources to meet 

specific energy or capacity demand needs. Wind is added for its environmental, economic and 

risk reduction benefits. Additional utility risk reduction benefits can accrue from the ability to 

construct wind projects to match the timing and scale of load growth. 

An analysis performed by the Council indicates that in the Northwest, a new, must-run resource 

such as wind generation will displace natural gas more than 80 percent of annual hours.5

 In this 

analysis, coal was displaced about 10 percent of hours and other resource types the remaining 

hours. The economic and environmental benefits of fuel displacement are a function of the fuel, 

heat rate and emissions control characteristics of the displaced resource. This pattern of 

displacement is desirable (and logical) from an economic standpoint, since natural gas prices 

are higher and more volatile than coal (although coal prices and volatility have also increased 

in recent years). However, it would be preferable from an environmental perspective to

displace coal instead of natural gas, as CO2 and criteria pollutant6

 reductions would be greater. 

Northwest wind resources and wind project development 

The Pacific Northwest has many good, though scattered, wind resource areas. A good wind 

resource area receives sustained strong winds averaging seven meters per second (16 mph) or 

more.7

 The area will have smooth topography and low vegetation to minimize turbulence, 

sufficient developable land to achieve economies of scale, nearby transmission lines with 

available capacity, complementary land use and an absence of sensitive species, habitat, 

cultural features and aesthetic qualities. Ideally, daily and seasonal wind patterns will coincide

with electrical load. 

The red, purple and pink areas of Figure 1 indicate potentially productive wind resource areas. 

Land east of the gaps in the Cascade and Rocky Mountain ranges receive concentrated, 

prevailing, storm-driven westerly winds, as well as wintertime, northerly winds. This also 

occurs in Washington’s Kittitas County, the Columbia River Plateau east of the Columbia 

River Gorge and the Blackfoot area east of Montana’s Marias Pass. Ridges perpendicular to 

prevailing winds in the Basin and Range areas of southeastern Oregon and southern Idaho also 

receive strong winds. East of the Rocky Mountains, nearly any landform above the general 

 5

 Northwest Power and Conservation Council. “Power System Marginal CO2 Production Factors.” Whitefish, 

Montana, April 2006. 6 These include oxides of sulfur, oxides of nitrogen, particulates, hydrocarbons and mercury. 7

 At 50 m elevation 

15
elevation will have good winds. There, wind is concentrated at gaps between local ranges, such 

as at Judith Gap in Montana. 

Figure 1: Northwest wind resources and wind project development 

Operating

Under construction

Expected to be constructed in near-term

100 MW (area proportional to installed capacity)

Operating

Under construction

Expected to be constructed in near-term

100 MW (area proportional to installed capacity)

Operating

Under construction

Expected to be constructed in near-term

100 MW (area proportional to installed capacity)

Because of complex topography, land use and environmental limitations, not all of the good 

wind resource areas shown in Figure 1 will be developable. Wind power development in 

coastal areas, for example, will be constrained by steep topography, forest cover and aesthetic 

concerns. 

Wind power development in the Northwest has been largely concentrated in areas of 

compatible land use (open range and dryland wheat farming), favorable wind and access to 

available firm transmission capacity to the load centers west of the Cascades. The green and 

blue circles in Figure 1 represent individual projects and are proportional in area to installed 

capacity. Green circles are projects in commercial service and blue are projects under 

construction as of December 2006. 

The concentrated development to the east of the Columbia River Gorge is evident. Of the 2,170 

MW of wind projects in service and under construction regionwide, 875 MW (40 percent) are 

within the McNary-John Day transmission corridor just east of the Gorge. Another 425 MW

(20 percent) lie slightly further east in the Wallula Gap-Walla Walla area. While not having the 

best wind resources of the region, this area has compatible land use, reasonably favorable wind, 

and, to date, sufficient available firm transmission capacity with access to the load centers west 

16
of the Cascades. The concentration of wind projects in this area will continue to grow in the 

near-term. The yellow circles represent planned projects with announced contracts for which 

construction is expected to begin within the near future.8

 

Additional development east of the Columbia River Gorge is likely. Shown in Figure 2 are 

circles depicting the magnitude of active requests to regional transmission providers for 

interconnection of proposed wind projects. The circles of Figure 2 are at the same scale as the 

circles of Figure 1, but are county level aggregates, not individual projects.9

 Nearly 9,900 MW

is represented – in addition to the capacity depicted in Figure 1. Though few expect a large 

fraction of this capacity to be developed in the near future, it is evident from Figure 2 that the 

interest in sites at the east end of the Gorge persists. Nearly 6,200 MW (63 percent) of 

interconnection requests are for projects within six counties at the eastern end of the Gorge. 

While good winds and compatible land use are essential components of a suitable wind project 

site, transmission has emerged as the key driver of project location in the Northwest. The 

location of so much proposed wind development east of the Gorge is symptomatic of the 

availability to date of transmission to Northwest load centers. Because the northern terminals of 

the southern interties are within the Lower Columbia area east of the Gorge, California’s 

growing demand for renewable resources, driven by that state’s aggressive renewable portfolio 

standard, is likely to become an increasingly significant driver of wind development in this 

area. The impact on wind development of possible new transmission lines is also evident in the 

figure. The blue circle in north-central Montana represents projects that would be serviced by 

the proposed MATL transmission line north to the Calgary load area. 

 8

 “Planned” projects shown in Figure 1 are those with announced power sales agreements or intention to proceed, 

a conservative assessment of likely project development over the next two years. Additional projects hold permits 

and have secured or have been offered firm transmission capacity and may proceed with construction if customers 

are secured. 9

 FERC rules prohibit revealing the name or location beyond the county level of projects requesting 

interconnection until the interconnection agreement is in place. 

17
Figure 2: Wind project interconnection requests 

Interconnection requests

Interconnection requests (MATL) 

100 MW (area proportional to requested capacity)

Interconnection requests

Interconnection requests (MATL) 

100 MW (area proportional to requested capacity)

Interconnection requests

Interconnection requests (MATL) 

100 MW (area proportional to requested capacity)

Interconnection requests

Interconnection requests (MATL) 

100 MW (area proportional to requested capacity)

The capacity value of wind 

The atmospheric drivers of wind have implications for the Northwest during certain weather 

patterns, especially in the winter months. Periods of extreme low temperatures and high loads 

tend to occur when the region is affected by large-scale, high-pressure systems. These systems 

produce very little pressure variation across the region, and hence, an absence of wind. Also, 

there is recent evidence that a similar phenomenon occurs during extremely high temperatures 

and loads. The correlation between temperature and the availability of the wind is illustrated in 

Figure 3, using data from four wind projects in the BPA system. The lowest availability of 

wind clearly occurs during times of especially high and low temperatures.

10 

 10 Additional data is needed to determine the extent to which such high-pressure systems can idle projects across 

the four-state region, and this question will be further explored in the subsequent phase of this project. Also, 

current wind turbine technology is capable of higher capacity factors at lower wind speeds than the technology 

underlying the data of Figure 3. 

18
Figure 3: Wind production relative to load center (Portland, Seattle, Spokane) temperature 

(BPA Projects, 2001-2006) 

Wind Gen (% Nameplate) for Various Temperature regimes

(All hours 2001-2006)

0%

5%

10%

15%

20%

25%

30%

35%

40%

45%

50%

55%

60%

65%

70%

75%

80%

85%

90%

95%

100%

0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100%

Cum Prob

Win

d Gen (

%

N

a

m

epl

ate)

All days

x<25F

30F>x>25F

40F>x>30F

50F>x>40F

60F>x>50F

70F>x>60F

80F>x>70F

85F>x>80F

x>85F

Since extreme heating and cooling events frequently are driven by high-pressure weather 

systems and stagnant air, it can be expected that the contribution Northwest wind resources will 

make to meeting loads at these times will be less than their average capacity factor. For 

example, during the extreme heating event of July 24, 2006, the regional wind fleet as a whole 

generated at 5 to 10 percent of nameplate capacity. On November 27, 2006, during the peak 

load hour of a regional cold snap, the combined wind projects of BPA and NorthWestern 

Energy generated at 3 percent of their nameplate capacity. 

Single-hour or daily peak period capability is not the limiting factor for system reliability 

because of the short-term storage and shaping capability of the Northwest hydroelectric system. 

The Northwest Resource Adequacy (NWRA) Forum’s capacity adequacy metric bases the 

sustained peaking capacity value of a resource on its average contribution to the system over 

five sequential 10-hour peak load days (the 50-hour sustained capacity).11 For its pilot capacity 

standard, the NWRA Forum has assigned a provisional, 15 percent sustained peaking capacity 

value to wind. The wind fleet performance during peak load events suggests that the 15 percent 

figure may be too high. As a result, the NWRA Forum has agreed to reassess the capacity 

contribution of wind. 

 11 Individual utility systems with less access to hydro resources may use different approaches to determining the 

capacity contribution for the wind in their portfolios. 

19
The fact that wind energy contributes relatively little sustained peaking capacity to the power 

system means that with or without wind energy, Northwest utilities will need to rely on other 

capacity resources (thermal, renewable, or demand-side) to meet their peak load requirements. 

Wind power will be added as a variable and complementary energy resource to a portfolio of 

firm capacity resources. 

The relatively low capacity contribution of wind does not negate the fundamental value 

proposition of wind energy: it displaces fossil fuels and their associated emissions and 

exposure to price volatility and uncertainty. 

ACTION 1: By July 2007, the Northwest Resource Adequacy Forum (NWRA Forum) should 

reassess its 15 percent pilot sustained wind capacity value using currently available data on wind 

plant operation during periods of peak load. In 2008, the NWRA Forum should further refine 

the sustained peaking capacity value of wind power using the improved wind resource data set of 

Action 3 and other available data. 

Wind energy behaves like negative load and increases net system variability 

and uncertainty 

The moment-to-moment and hour-to-hour variability of wind makes it behave much more like 

negative load than traditional generation. Wind energy is not fundamentally different from

anything control area operators have to deal with when managing load variability. However, 

one megawatt of new wind is significantly more variable and less predictable than one 

megawatt of new load. 

Viewing wind generation as a negative load rather than as a source of generating capacity 

makes it easier to understand its impact on system operations. All utility systems are designed 

to manage load variability and forecast error. This variability and uncertainty by itself is 

substantial; BPA and other control areas regularly deal with load changes of several thousand 

megawatts during morning and nighttime ramping periods. The systems manage these changes 

without difficulty under the vast majority of conditions. Given that even the most dispatchable 

generation technologies have some variability and uncertainty, the objective of control area 

operations is to manage net system variability and net system uncertainty. When wind energy is 

added to the equation, its variability and uncertainty becomes part of this net system variability 

and uncertainty. 

At low wind penetration levels, the amount of variability introduced by a small amount of wind 

is virtually lost in the larger fluctuations of loads. As the amount of wind increases, the effects 

of wind variability dominate the effects of load variability and the ranges of net system 

variability and net system uncertainty increase. This places additional demands for system

flexibility across two main time horizons: within-hour (1-60 minute) and hour-to-hour. An 

example of variability across these horizons is portrayed in Figure 4. 

20
Figure 4: Illustrative diurnal output of a wind plant 

Actual Wind Plant Output

0.0

10.0

20.0

30.0

40.0

50.0

60.0

70.0

80.0

90.0

100.0

123456789 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24

Wind integration in the within-hour time frame 

Wind increases the demand for additional regulating (several second response time) and load 

following (several minute response time) reserves in the within-hour time frame. Control areas 

carry regulating reserves to manage the minute-to-minute changes in their load and resource 

balance. Northwest control areas also carry load following reserves to maintain system balance 

across the remainder of the scheduling period (60 minutes in the Northwest). Regulation and 

load following reserves are types of operating reserves. Other types of operating reserve 

include contingency reserves for responding to sudden unplanned generation or transmission12

outages. 

Figure 5 illustrates the combined within-hour behavior of 208 MW of installed capacity from

four wind projects in the BPA system. The figure depicts the probability distribution of wind 

output changes, as megawatts up or down, over the 1-minute, 10-minute and 60-minute time 

horizons. As can be seen, for all three series, the variability is clustered around zero with low 

probabilities of occurrence in the tails of the distributions. 

 12 Under current rules, wind projects are treated like hydro resources from the perspective of contingency reserves. 

21
Figure 5: Short-term generation step changes for wind projects in the BPA control area 

Generation Step Changes

(aggregate project performance)

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

-20 -15 -10 -5 0 5 10 15 20

Generation Change (MW)

O

ccure

nce Pro

b

a

bility

1-min change

10-min change

1-hour change

2.5% of Nameplate

5% of Nameplate

Figure 5 illustrates how step changes increase with the time step considered. Incremental 1-

minute regulating reserves necessary to manage wind energy – even for a large wind fleet – are 

quite small compared to existing requirements. This is because wind project output seldom

changes dramatically over very short time intervals, and wind turbine output – even in 

individual wind projects of medium to large size – is not highly correlated with load across the 

regulating time frame. Changes in wind turbine output across the load following timeframe (10 

to 60-minutes) are larger due to higher correlation between wind projects on that timescale. 

Changes in wind power output over the load following time horizon are a larger driver of the 

incremental demand for within-hour reserves than are the changes occurring in the regulation 

time frame. 

Predicting the absolute level of wind over a given hour provides a second challenge to 

integrating wind energy. Wind forecast errors must be evaluated in combination with the other 

sources of uncertainty in system operations, especially load forecast errors. BPA evaluated the 

forecast errors of these same four wind projects from 2001-2006. It found the distribution 

shown in Figure 6:

22
Figure 6: Distribution of forecast errors for BPA wind projects 

Hourly Forecast Error

-160

-140

-120

-100

-80

-60

-40

-20

0

20

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60

80

100

120

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160

0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100%

Cum Prob

Forecast Error (

M

W)

-70%

-60%

-50%

-40%

-30%

-20%

-10%

0%

10%

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F

orecast Error (

%

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a

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e

plate)

Hour+3

Hour+6

Day_1

Day_3

Day_5

Hour+1

As shown, the quality of the wind forecasts improves dramatically from five days ahead to one 

hour ahead. For the one-hour ahead forecast, 90 percent of the wind forecast errors vary 

between minus 10 percent and plus 15 percent. These uncertainties are partially mitigated by 

combining wind and load forecasting. Good wind forecasting is an essential element of 

managing wind power and mitigating the costs of wind forecast error. 

Northwest system operators must have access to sufficient regulation and load following 

reserves to meet the incremental variability and uncertainty created by wind. Operators with 

sufficient system flexibility will be able to secure all or a portion of the incremental operating 

reserves by changing how they operate their existing fleet of assets. This likely will result in 

reduced operational efficiency. Examples of this lost efficiency include running units out of 

economic merit order and placing generating capacity that otherwise would be used for shortterm secondary energy marketing on reserve status. Where and if flexibility becomes 

exhausted, utilities will have to procure flexibility from neighboring control areas, install 

controls or other equipment to increase the existing system’s flexibility, or develop new 

generating or demand-side resources capable of providing the needed flexibility. 

For BPA and other hydro-dependent control areas, one of the most salient examples of running 

units out of economic merit order involves operating hydro facilities more actively at night to 

secure additional ramp-down capability. Since the primary economic objective of hydro 

operations is to conserve water for release during the most valuable time periods (usually the 

peak load hours of the day), this will shift hydroelectric generation from peak to off-peak load 

periods, creating opportunity costs. In Section V, this Action Plan discusses the considerable 

23
benefits – and periodic challenges – of using hydro resources as the principle source of 

operating reserves to integrate wind. 

Within-hour regulating and load following reserves also ensure that power transfers between 

control areas are delivered according to hourly schedules. For example, if a wind project 

located in one control area schedules 100 MW for delivery to another control area, the host 

control area must use its regulation and load following reserves to ensure that 100 MW of 

power is actually delivered, even if the wind project deviates substantially from its schedule. In 

vertically disaggregated utilities operating under the provisions of FERC’s Open Access 

Transmission Tariff (OATT), within-hour operating reserves are supplied by the transmission 

side of the business. 

Managing wind energy in the hour-to-hour time frame 

Figure 7 depicts the hour-to-hour shape of wind output after the control area has managed its 

within-hour variability. These changes in forecasted hour-to-hour output are managed by the 

power side of the business through the dispatch of generating assets or by making balancing 

purchases and sales. For larger utilities with sufficient generation flexibility to avoid overdependence on balancing purchases and sales, hour-to-hour changes may have little additional 

cost impact. However, smaller utilities and wind developers, who must rely more actively on 

the market to balance the hour-to-hour changes in wind generation (or deviations from dayahead forecasts), may incur costs associated with market illiquidity and volatility. Some may 

choose to purchase additional services to help manage this variability, if such services are 

available. 

Figure 7: Wind output after within-hour integration by a control area 

Wind Plant Output after Within Hour Integration by Control Area

Based on the Hourly Forecast

0

10

20

30

40

50

60

70

80

90

100

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24

Several of the region’s utilities and marketers have developed wind integration services, though 

few are offering them today. For example, BPA’s Storage and Shaping Service (S&S) and 

Network Wind Integration Service (NWIS) were developed to convert variable amounts of 

24
wind energy into predictable blocks of energy for later delivery (S&S Service) – or to manage 

the hour-to-hour variability of wind output on behalf of requirements customers (NWIS). BPA 

offers neither service today. Grant County PUD and PacifiCorp have offered similar services, 

and some wind developers have also offered products that mitigate the hour-to-hour variability 

of wind. Figure 8 depicts the shape of wind power output in Figure 7 after it has been stored 

and shaped for redelivery into flat blocks of peak and off-peak energy. 

Figure 8: Wind output after purchasing a storage and shaping service 

In the Northwest, hour-to-hour shaping services have generally been sold by the power (or 

“merchant”) side of regional utilities. These commercial power products typically have not 

included specific payments for within-hour balancing services that must be simultaneously 

purchased from the transmission side of the business.13 The market for shaping services is, at 

present, extremely limited. This is also true of the market for within-hour balancing services. 

This Action Plan explores the root causes of this lack of market depth, and potential ways to 

expand the market for these products in Section V. 

Wind integration costs are driven by the costs of securing and dispatching 

incremental operating reserves and managing hour-to-hour changes in wind 

output 

The opportunity costs associated with the operational or marketing changes required to carry 

additional operating reserves are the chief source of wind integration costs. There may also be 

additional wear and tear on hydro and other units, as well as efficiency losses resulting from

the additional cycling. Together, these direct and opportunity costs are the underlying drivers 

of wind integration typically reported in utility wind integration studies. Additional costs may 

be incurred to manage the hour-to-hour changes in wind output or differences between dayahead schedules and actual hourly output. 

 13 Most but not all transmission providers purchase the generation inputs for their ancillary services from their 

merchant functions. NorthWestern Energy, one exception, purchases such services from the market. 

25
Extreme ramping events are infrequent but must be managed in order to 

maintain system reliability 

As further discussed in Section V, many of the region’s investor-owned and public utilities r

primarily on hydroelectric facilities for regulation and load following reserves. With increas

amounts of wind, there will be occ

ely

ing

asional periods when large unexpected changes in wind 

de:

s

during these large wind events can be achieved by limiting wind project ramp rates 

r output until such time as additional system flexibility becomes available. Preliminary 

ility to transmit data and receive instructions from the 

ontrol area operator in order to participate in system balancing mechanisms and help protect 

ion

r.

nd

Northwest wind projects are using

odern turbine designs capable of dynamic performance comparable with that of conventional 

d at

lly diversifying wind projects reduces total wind 

improves aggregate wind 

ectly into lower wind 

output (“wind ramps”) occur during conditions of limited hydro flexibility. This will lead to 

reliability issues (CPS2 violations) unless the control area operator can restore system balance 

in other ways. Other means of managing large unexpected changes in wind generation inclu

marketing the wind power on short notice (which may be very difficult given the Northwest’

current market structure), backing down other generation such as gas or coal plants, energizing

pump storage units, activating dispatchable loads such as irrigation pumps, spilling 

hydroelectric energy (if not environmentally constrained), or reducing the output of the wind 

projects. 

If more cost-effective sources of system flexibility have been exhausted, maintaining system

reliability

o

analysis indicates that these are low probability events. Further study of the frequency and 

magnitude of these events is necessary. 

FERC, in Appendix G of its standard Large Generator Interconnection Agreement, requires

wind plant operators to secure the capab

c

system reliability. Wind project output control will be implemented through the interconnect

agreements between project owners and control area operators. Managing severe wind ramps 

will require new tools for control area operators. Because limitations on wind output will 

impact wind project economics, this Action Plan recommends that Northwest control areas 

work with wind developers, and through a rigorous cost/benefit analysis, seek to achieve the 

reliability requirements of Appendix G in a mutually satisfactory and cost-effective manne

Beginning in mid-2007, BPA will conduct a public process for implementing its economic a

operational framework for active wind output control.

FERC has also established dynamic performance requirements for wind turbines to help 

support grid security and stability. As a result, most new

m

generation. Dynamic performance is an interconnection wide issue, and is being addresse

the Western Electricity Coordinating Council (WECC) through modeling, performance 

evaluation and standard setting. It is recommended that Northwest stakeholders continue to 

support and participate in these activities. 

Creating a geographically diverse, low cost wind fleet 

It is widely acknowledged that geographica

fleet variability, lowers the probability of large ramping events, and

forecasting accuracy. Lower variability and uncertainty translates dir

integration costs. Preliminary results of Avista’s 2007 wind integration study confirm the 

26
benefits of geographical diversification as do a number of studies from other parts of the 

country including the recently released Minnesota wind integration study.14

Access to wind sites with higher capacity factors such as those in Montana, and the ability to

iversify wind generation patterns, will result in lower busbar and wind integration costs (all 

,

e

n

 

d

else being equal). A one percent increase in capacity factor can reduce busbar costs by

$2.50/MWh. To achieve the economic and operational benefits of geographical diversification

wind projects will need sufficient transmission capacity to move their power to load. Th

challenge to our region is finding a way to meet the transmission requirements for wind energy 

at the lowest possible cost to regional ratepayers. The current practice of relying entirely o

firm transmission capacity for an energy resource with little firm capacity contribution needs to 

be revisited. Transmission planning for new wind resources also needs to be conducted in the

larger context of regional generation and transmission planning. This Action Plan discusses this 

issue in greater detail in Section III. 

14 Final Report, Minnesota Wind Integration Study. Prepared for the Minnesota Public Utilities Commission by

EnerNex Corporation in cooperation with the Midwest Independent System Operator, November 2006. 

27
II. Operational capability and costs of integrating wind in the 

Northwest 

This section summarizes the preliminary findings and conclusions of five initial Northwest 

wind integration studies. Appendix B contains a more detailed discussion of the individual 

study methodologies. 

Overview of studies 

The costs of wind integration are driven by the need to secure additional operating flexibility 

on several timescales to balance fluctuations and uncertainties in wind output. The Technical 

Work Group reached general agreement on wind integration cost-causation mechanisms given 

the block hourly day-ahead and real-time market structure currently in place in the Northwest. 

Three Northwest utilities – Avista, Idaho Power and BPA – have performed new wind 

integration studies that reflect the unique characteristics of their systems. Previous studies by 

Puget Sound Energy (2003) and PacifiCorp (2001, 2004) addressed similar cost-causation 

mechanisms. 

The Avista, Idaho Power, Puget and PacifiCorp studies evaluate the costs of integrating wind 

energy for native load service. They reflect both within-hour and hour-to-hour costs of

integrating wind energy. BPA focused initially on within-hour costs to help inform future 

revisions to ancillary service tariffs and rates that will be needed to address the rapid growth of

wind projects interconnecting to the federal system, but serving nonfederal loads. BPA plans to 

revise its cost estimates and analyze wind impacts on its hour-to-hour operations in 2007. 

Cautions and caveats 

Preliminary cost estimates from the initial Northwest wind integration studies are cited below. 

The studies represent a significant step forward in regional understanding of wind integration 

costs, but it should be carefully noted that the cost figures and methodologies underlying the 

studies are still the subject of debate among members of the Technical Work Group. Revisions 

to several of the studies are still under way. All of the utilities reporting results intend to revisit 

their study methodologies and results as better data and analytical techniques become available. 

The cost estimates will eventually be translated into formal rates and/or market prices that may 

deviate from the numbers cited below. The cost estimates are also based on current system

obligations and constraints that are subject to change. Future reductions in system flexibility 

could result in higher costs. The costs may also come down as a result of ongoing study 

revisions, greater control area coordination, or other cost-reduction strategies. The most current 

officially released study results are posted on the Council’s Website at 

www.nwcouncil.org/energy/Wind and will be updated on a regular basis. 

Since the initial BPA study only addressed within-hour impacts, the BPA integration cost 

estimates are shown separately and likely represent a low-end estimate of wind integration 

costs on the BPA system. 

28
Wind penetration levels 

There are 1,400 MW of wind energy installed in the Northwest. Table 3 shows the amount of 

implied wind capacity in each utility control area as a function of increasing wind penetration 

levels. 

Table 3: Wind capacity as a function of penetration level (percent of peak load), by utility 

Utility Peak Load (MW)

5% 10% 20% 30% 35% 45%

Avista 2,200 110 220 440 660 770 990

Idaho Power 3,100 155 310 620 930 1,085 1,395

Puget Sound Energy 4,650 233 465 930 1,395 1,628 2,093

PacifiCorp 9,400 470 940 1,880 2,820 3,290 4,230

BPA 9,090 455 909 1,818 2,727 3,182 4,091

Total 28,440 1,422 2,844 5,688 8,532 9,954 12,798

Wind Capacity at Different Penetration Levels (MW)

Of the 16 control areas in the Northwest, only six are represented in this table (including 

PacifiCorp East and PacifiCorp West). NorthWestern Energy, which has been active in the 

wind sector and is anticipating continued growth of wind in its control area, is not represented. 

Portland General Electric (PGE), another major investor-owned utility, Seattle City Light, 

Grant County PUD and other large generating publics are not represented either, yet some of 

these utilities may integrate additional wind into their control areas. 

The five utility studies evaluated different levels of wind penetration on their systems. Puget 

examined up to 10 percent wind penetration, PacifiCorp evaluated up to 20 percent, Avista and 

Idaho Power up to 30 percent, and BPA up to 33 percent. Table 4 converts these percentages 

into installed megawatts. 

Table 4: Maximum wind penetration levels modeled in initial Northwest studies 

Utility Peak Load (MW) Penetration Level (%) Installed Capacity (MW)

Avista 2,200 30% 660

Idaho Power 3,100 30% 930

Puget Sound Energy 4,650 10% 465

PacifiCorp 9,400 20% 1,880

BPA 9,090 33% 3,000

Total 28,440 6,935

Based on assumptions about current levels of system flexibility, access to the wholesale 

marketplace, and the occasional use of alternative sources of flexibility including wind output 

control, the utilities determined that their systems were operationally capable of achieving at 

least the maximum wind penetration levels modeled in their studies. This equated to 6,935 MW

of wind. 

The Northwest wind integration studies are based on existing system obligations and resources. 

Over time, with load growth and other demands on system flexibility, some of the utilities may 

need to procure additional operating reserves or invest in new generating resources capable of 

providing the needed flexibility. However, there are no fundamental technical barriers to 

29
deploying additional sources of flexibility. This is evidenced in other regions of the country 

such as Colorado and Texas that depend primarily on gas turbines to provide wind integration 

services. As a result, based on the initial results in Table 4, and the fact that only six of the 16 

Northwest control areas are represented in the results, there do not appear to be any 

fundamental technical barriers to integrating 6,000 MW of wind in the Northwest. It’s a 

question of cost. 

Cost estimates 

Table 5 presents the preliminary cost estimates expressed in $/MWh of wind generation by 

increasing amount of wind penetration (nameplate wind/peak load). 

Table 5: Preliminary wind integration costs from initial utility studies ($/MWh of wind 

generation)15

Utility Peak Load (MW) 5% 10% 20% 30%

Avista 2,200 $2.75 $6.99 $6.65 $8.84

Idaho Power 3,100 $9.75 $11.72 $16.16

Puget Sound Energy 4,650 $3.73 $4.06

PacifiCorp 9,400 $1.86 $3.19 $5.94

Utility Peak Load (MW) 5% 10% 20% 30%

BPA (Within-Hour Impacts Only) 9,090 $1.90 $2.40 $3.70 $4.60

NorthWestern Energy has reported to the Montana Public Service Commission a wind 

integration cost of $6.75/MWh for the Judith Gap project for 2006. This value is yet to include 

the expenses for the operation of the Basin Creek gas-fired plant that are solely attributable to 

wind integration. The wind integration costs for Basin Creek have not been finalized for 2006. 

The NorthWestern control area has a wind penetration of 8.7 percent and is currently 

purchasing all of its control area services at market-based rates. 

Key findings 

Based on Northwest studies and others from around the world, the cost of wind integration is 

largely dependent on: (1) the size of the control area where such services are procured in 

relation to the amount of wind being integrated; (2) the geographic diversity16 of wind sites and 

resultant generation patterns; (3) the amount of flexibility available to the power system, and 

(4) access to robust markets for control area services and storage and shaping products. 

Table 5 illustrates a general trend of lower wind integration costs with increasing control area 

size. The Avista numbers also shine light on the benefits of geographical diversification. By 

virtue of purchasing a more geographically diverse portfolio of wind projects under its 20 

 15 BPA evaluated the current amount of wind in its system (733 MW) and then evaluated costs at 1,000 MW (11 

percent penetration), 2,000 MW (22 percent) and 3,000 MW (33 percent). For ease of comparison, the percentage

figures have been rounded down slightly in Tables 5 and 6. 16 Diversity in this context refers to the extent to which changes in wind output at one wind site are different from

the changes at other wind sites. 

30
percent penetration case relative to its 10 percent case, Avista is able to double the amount of 

wind in its system while simultaneously lowering its per-megawatt hour costs. 

Wind integration costs are also driven by dynamic market variables and the amount of system

flexibility available to each utility. For hydro-dependent utilities that provide flexibility from

their own resources, wind integration costs are largely a function of the spread between peak 

and off-peak power prices, and current water supply conditions. For control areas with 

insufficient flexibility to manage their own wind resources, wind integration costs are a 

function of the market price for control area services and other required shaping products. 

Absent access to other sources of flexibility, utilities will need to invest in new generating or

demand-side resources to secure the needed flexibility. 

Several of the studies also found that integration costs were very sensitive to the absolute level 

of wholesale energy market prices. Where market prices rise or fall by 50 percent from today’s 

levels, integration costs would also be expected to change by a similar percentage. Table 6

expresses the individual utility wind integration costs as a percent of the wholesale price of 

electricity embedded in each of the studies. 

Table 6: Preliminary wind integration costs from initial utility studies expressed as a percent of 

wholesale electricity market prices 

Utility Peak Load (MW) 5% 10% 20% 30%

Avista 2,200 5.0% 12.7% 12.1% 16.1%

Idaho Power 3,100 15.5% 18.7% 25.8%

Puget Sound Energy 4,650 6.2% 6.8%

PacifiCorp 9,400 3.1% 5.3% 9.9%

 

Utility Peak Load (MW) 5% 10% 20% 30%

BPA (Within-Hour Impacts Only) 9,090 3.2% 4.0% 6.2% 7.7%

Using Table 6, it is possible to estimate wind integration costs at various levels of wind 

penetration and market prices, and to normalize the wind integration cost estimates of 

individual studies that may have been based on different electricity market prices. 

The Northwest wind integration supply curve 

Conceptually, regional wind integration costs can be represented as a supply curve relating cost

to the level of installed wind capacity. The incremental costs start out very low, as the amount 

of variability introduced by a small amount of wind is virtually lost in the larger fluctuations of 

loads. As the amount of wind increases, the effects of wind variability ultimately dominate, and 

flexibility needs to be added to the system in direct proportion to the growing wind penetration. 

Some analysts suggest that there is an upper limit on how high wind integration costs can go 

based on the cost of gas-fired resources. 

Consider a combination of a wind project and a gas turbine, each with the same nameplate 

capacity. The two projects are operated to meet a fixed, contractual amount equal to their 

individual nameplate capacity – the wind project offsets the gas resource when the wind blows. 

31
For example, a 300 MW wind farm could contract with a 300 MW gas plant to serve a fixed 

300 MW contract delivery. When the wind blows, the gas resource backs down. 

Operating a gas plant in that way incurs costs due to lower efficiency, increased operating and 

maintenance costs, possible plant modifications for controls and ramping capability, and 

potentially fuel contracting costs due to the variability and uncertainty of wind. It is reasonable 

to consider these the wind integration costs. With gas resources being relatively available, this 

may represent an upper limit on wind integration costs. As discussed in Section V, however, 

other supply and demand-side technologies may play an increasing role in providing system

flexibility over time. 

A conceptual wind integration supply curve is represented in Figure 9. 

Figure 9: Conceptual Northwest wind integration supply curve 

0

10

20

30

40

50

60

70

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21

Installed Wind Capacity

Inte

gratio

n C

o

st (

$/M

W

h)

Cost cap - integration services from

existing or new gas-fired power plants

Given differences in the types of costs addressed by the studies, as well as the limited number 

of Northwest utility studies represented in this report, it is not yet appropriate to collapse the 

individual utility supply curves reported above into a single supply curve for the region. Over 

the coming year, a better understanding of the composite Northwest wind integration supply 

curve should emerge as the utilities participating in the Northwest Wind Integration Forum

continue to refine their study methodologies and estimates of the wind integration costs using a 

robust stakeholder input process. They also will estimate the potential for shifting the supply 

curve to the right through control area cooperation, more active markets for control area 

services and other strategies to reduce costs or extend integration capability. 

ACTION 2: Utilities participating in the Northwest Wind Integration Forum should 

continue to refine their study methodologies and estimates of wind integration costs using 

32
a robust stakeholder input process. They should also estimate the potential for reducing 

the cost and extending the supply of wind integration services through control area 

cooperation, more active markets for within-hour balancing services and other strategies. 

Addressing data limitations 

The Northwest does not possess wind data adequate to quantify the benefits of cooperative 

operational strategies, to evaluate the benefits of geographical diversification, to inform 

transmission planning efforts, and to fully evaluate the capacity value of wind. As part of the 

Northwest Wind Integration Forum, the Steering Committee has agreed to fund the 

development of a better data set. Appendix C provides technical requirements and a cost 

estimate for a Northwest chronological wind data set. 

ACTION 3: The Northwest Wind Integration Forum should contract for the development of a 

high-resolution chronological wind resource data set for the Pacific Northwest. The data set 

should be available by December 2007. 

Summary of wind integration studies from other regions 

More than 200 wind integration studies have been performed over the past decade.17 Most 

come from utility systems outside of the United States, and many do not benefit from current 

state-of-the-art methodologies and datasets. However, a number of recent studies have used 

methodologies based on best practices. Table 7 summarizes results from several recent wind 

integration studies outside of the NW. 

Table 7: Selected extra-regional wind integration study results

Study Study Spot Integration

Year Name Penetration Market Cost

(percent) (minutes) ($/MWh)

2003 Xcel-UWIG 4 N/A 1.85

2003 WE Energies 4 1.90

2003 WE Energies 29 2.92

2004 Xcel-MNDOC 15 N/A 4.60

2004 VTT-Scandinavia 10* 1.29 ***

2004 VTT-Scandinavia 20* 2.58 ***

2006 Xcel-PSCo 10 N/A 3.72

2006 Xcel-PSCo 15 N/A 4.97

2006 Enernex-MN 2** 5 2.11

2006 Enernex-MN 3** 5 4.41

* Penetration based on MWh generation / MWh load

** Penetration based on MISO footprint

***Euros/MWh converted to dollars @ 1.29 Euro/dollar

 17 The Costs and Impacts of Intermittency: An assessment of the evidence on the costs and impacts of intermittent

generation on the British electricity network, March 2006. 

www.ukerc.ac.uk/component/option,com_docman/task,doc_download/gid,550/

33
While informative, care must be taken when making comparisons between these studies and 

wind integration costs in the Northwest. This is because the studies come from regions with 

different:

 Market structures 

 Wind penetration levels 

 Wholesale market prices 

 Wind generation resource characteristics 

 Nonwind resource mixes 

 Interconnections to other systems 

Market structure 

Market structures vary considerably across the United States. In the Northwest, there are three 

bilateral wholesale energy markets: a forward market (balance of month to one year or more), a 

day-ahead market, and an hourly “real time” market. The day-ahead and hourly “real time” 

markets trade in 60-minute blocks. There are no formal, structured markets for within-hour 

regulation or load following. The Northwest has 16 individual control areas, several of limited 

size. 

Several regions of the country have much larger control areas and administer shorter-term

markets for ancillary services. As demonstrated in Table 5, larger control areas spread the 

variability and uncertainty of wind over a larger portfolio of loads and resources, which results 

in cost savings relative to smaller control areas. Preliminary analysis by Avista indicates that 

shorter market timeframes can reduce wind integration costs by 20 percent to 60 percent, due in 

large part to the reduced wind forecast errors associated with shorter-term scheduling windows. 

Studies from other parts of the country reflect varying degrees of access to shorter-term

markets. The recent EnerNex-Minnesota study was modeled in a five-minute market with 

access to the within-hour balancing resources of the entire Midwest Independent System 

Operator (MISO) footprint. Adjusting for this major difference in market structure could 

significantly increase estimated costs for Minnesota. A full discussion of the pros and cons of 

various market structures is well beyond the scope of this document. However, in Section V, 

there is an exploration of ways to capture some of the benefits of larger control areas and 

ancillary services markets, without changes to the market structure of the Northwest. 

Wind penetration level 

Generally, wind integration costs rise as more wind is interconnected within a control area. One 

should not expect costs from one system study with a penetration rate of 5 percent to be similar 

to a study with a 20 percent penetration rate. 

Wholesale market prices 

Northwest integration studies confirm that wind integration costs are highly correlated with the 

absolute price of the wholesale marketplace. Higher market prices tend to lead to higher 

integration costs. 

34
Wind generation resource characteristics 

Wind patterns differ across the country. Wind patterns in one geographic location can be very 

volatile, while at another location wind speed variations are less pronounced. Some regions 

find that their various wind sites are not highly correlated, thereby reducing incremental 

operating reserve requirements. Improved wind data will help us better understand the extent of 

diversity in wind regimes in the Northwest. 

Nonwind resource mix

Resources available to integrate wind energy affect wind integration costs. Most regions in the 

U.S. use thermal plants to integrate wind. Some systems have a “deep” stack of flexible 

resources to provide balancing capacity, while others do not. The Northwest benefits from a 

large fleet of relatively flexible hydroelectric projects, though the amount of flexibility varies 

across its 16 control areas. 

Interconnections to other systems 

The nature and extent of interconnections with other systems affects study results. The 

EnerNex-Minnesota study assumed up to a 25 percent wind penetration level for the state of 

Minnesota. However, the state has strong interconnections with MISO and relies heavily on 

having non-Minnesota resources within MISO provide incremental balancing capacity for its 

proposed wind regime. The purported 25 percent penetration, when considering the MISO 

footprint, actually equates to a penetration level below 5 percent.18

 18 The Minnesota study assumed 5,700 MW of wind in 2020 to arrive at a 25 percent penetration level, whereas

MISO has a resource mix today of about 135,000 MW and would grow to approximately 180,000 MW by 2020 

assuming a 2 percent annual growth rate. 

35
III. Transmission requirements for integrating 6,000 megawatts of 

Wind

Wind project development in the Northwest generally has followed conventional practice, 

whereby long-term firm transmission capacity is secured for the full installed capacity of a 

generating project. Although firm transmission contracts have been awarded to many of the 

wind projects expected to come online before 2009, there is insufficient Available 

Transmission Capacity (ATC) to serve the full amount of wind power called for in the 

Council’s Fifth Power Plan. The lack of incremental ATC is becoming acute east of the 

Columbia River Gorge, where hundreds of megawatts of wind generation are under 

construction, and thousands of additional megawatts are proposed (see Figures 1 and 2). 

Montana and other parts of the region are facing similar transmission limitations. 

Utilities historically have procured long-term firm transmission for the full output of their 

generation facilities to ensure energy delivery during times of system peak. Moreover, 

transmission costs, when spread over the output of higher capacity factor resources, are low 

when compared to the busbar cost of the resource itself. 

Since wind is primarily an energy resource that makes relatively little contribution to meeting 

peak loads, utilities may significantly discount wind capacity and not count on it for reliability 

purposes. If guaranteed delivery in all situations is not needed for reliability, then providing 

firm transmission for the full installed capacity of a wind plant (or group of wind projects) is 

both unnecessary and economically inefficient. Moreover, with wind’s relatively low capacity 

factor, firm transmission may double or triple the transmission cost of wind energy compared 

to a higher capacity factor resource. A more economically efficient approach would be to 

provide a mix of firm, nonfirm, or conditional firm transmission service that seeks a balance 

between the marginal cost of transmission capacity and the marginal value of delivered wind 

energy. This approach will lead to better use of the transmission grid and lower delivered wind 

energy costs without compromising system reliability. 

This new transmission model will result in a mix of transmission products and selective 

transmission investment. New data and analytical tools will be needed to identify, characterize 

and evaluate alternatives, seeking the optimal balance between transmission investment and 

energy delivery. A reallocation of risk and compensation between wind project owners and 

utilities purchasing wind power may be needed to ensure that project owners are able to obtain 

financing. Creativity and regulatory support will be needed to bring this about. Despite the 

complexity of issues that must be resolved, the potential benefits of a new approach are 

compelling. Hence the following actions: 

ACTION 4: By September 2007, the Northwest Transmission Assessment Committee 

(NTAC) should propose a formal technical transmission planning methodology for 

regional wind development. This methodology should identify the data requirements and 

capacity and energy planning tools needed to identify the optimal level of transmission 

investment needed to efficiently serve future wind development. 

36
ACTION 5: By the end of 2007, Columbia Grid and the Northern Tier Transmission 

Group, working with NTAC should convene a joint session to begin applying the 

transmission planning methodology for regional wind called for in Action 4. 

ACTION 6: By the end of 2007, the four state regulatory commissions should review and 

commence to amend as necessary, regulatory policies to remove barriers to more efficient 

use of transmission for wind and other renewable resource development. To the extent 

feasible, policies should be consistent across states. 

In order to make more efficient use of the transmission system, mechanisms are needed to 

ensure that unused firm transmission rights can be transferred between users with sufficient 

advance notice to facilitate greater system utilization. More active reassignments of 

transmission can also promote voluntary economic redispatch during periods of transmission 

congestion that can help manage the risks associated with conditional firm and nonfirm 

transmission service. A pilot voluntary economic redispatch program should be developed and 

tested with the initial objective of using existing West of McNary transmission as effectively as 

possible. 

ACTION 7: BPA should continue development of mechanisms to promote greater 

utilization of the transmission system, including more active reassignments of firm

transmission rights, a conditional firm transmission product, and voluntary, multiparty 

economic redispatch mechanisms. BPA should report the results of these efforts to the 

Northwest Wind Integration Forum so that other transmission providers might benefit 

from this experience. The program, if successful, can be applied to integrating wind 

power from other transmission-constrained wind resource areas such as Montana. 

A number of factors, including load growth, conventional generating resource development and 

retirements, and the growth of wind energy are expected to eventually require reinforcement of 

the West of McNary/West of Slatt Corridor, the I-5 Corridor south of the Paul Substation, and 

possibly the Cross-Cascades North and South Corridors (Figure 10). The new transmission 

model called for above will require resolution of numerous technical and institutional issues. 

Success is not certain and may require several years. As a hedge against failure, and to prepare 

for the inevitable need for physical network reinforcements, engineering and economic 

assessments of potentially needed reinforcements should continue. These studies should 

incorporate new planning and analytical techniques as they are developed. 

37
Figure 10: Major transmission path constraints in the Northwest 

A proposed two-phase reinforcement of BPA’s main grid transmission network from McNary 

west towards The Dalles will greatly expand transmission capacity from eastern Washington 

and Oregon wind resource areas to load centers west of the Cascades. This expansion, coupled 

with current efforts to upgrade the Montana 500kV system, will improve access to higherquality wind resource areas lying farther east. The increased geographical diversity of projects 

may reduce the probability of extreme ramping events, improve aggregate wind forecasting 

accuracy, and reduce the demand for operating reserves to integrate wind. The reinforcements 

will also improve operating margins on the transmission system as a whole. 

Load growth and conventional generating resource development west of the Cascades is 

increasing transmission congestion in the I-5 Corridor, particularly south of Paul Substation. 

Loop flow from wind development east of the Cascades will exacerbate the problem. The need 

for additional Cross Cascades North and South transmission may be accelerated if dispatchable 

west side resources are turned down in response to wind availability during peak load periods. 

While this Action Plan does not advocate an immediate decision to proceed with construction, 

the urgency of these problems suggests that BPA should continue with measured steps to 

prepare for the eventual construction of these reinforcements. This will involve completion of

plans of service for the three reinforcements, with priority given to the I-5 Corridor and West 

of McNary projects, and an assessment of the business case for each. Environmental 

assessment and other preparations such as permitting and land acquisition would follow 

favorable business case findings to secure at least the option to build the lines. The new 

38
transmission model called for above should be incorporated into these planning efforts, as 

available. 

ACTION 8: By the end of 2008, BPA should work with regional stakeholders to complete 

plans of service for the proposed West of McNary Phase 1 and West of McNary Phase 2, 

the I-5 Corridor, and Cross-Cascades North and South transmission reinforcements with 

priority given to the I-5 Corridor and West of McNary projects. To the extent available, 

the plans of service should identify preferred upgrades using the capacity and energy 

transmission planning tools called for in Actions 4 and 5. The plans should include the 

estimated cost and the amount of commercially viable ATC for each upgrade. Upon 

completion, the plans and business cases should be reviewed by BPA’s Infrastructure 

Review Committee. 

Construction of any of these reinforcements will require a financing model for projects that, 

like these, are largely driven by development of new resources, as opposed to meeting 

reliability requirements for load service from existing resources with firm transmission rights. 

The financing model must address the Catch-22 confronting many wind project developers: 

they cannot make financial contributions to a new transmission line unless they have security in 

the form of a power purchase agreement; yet they typically cannot secure a power purchase 

agreement without a long-term transmission service agreement. Moreover, lead times for 

transmission reinforcement and expansion are much longer than for wind project development. 

This Action Plan recommends that BPA continue its development of a generally applicable 

approach for financing and recovering the costs of partly or wholly market-driven transmission 

reinforcements and expansions, using the West of McNary project as a prototype. Ideally, the 

approach would be also be applicable to renewable trunk line transmission primarily intended 

to serve multiple renewable resource projects located within a common resource area. 

ACTION 9: By the end of 2007, BPA should work with regional stakeholders to develop a 

generally applicable model for financing market-driven reinforcements and expansions of its 

transmission system using the proposed West of McNary project as a prototype application.

Finally, additional transmission system upgrades and expansions may be desirable over the 

longer-term to channel wind development to other prime wind resource areas. NTAC should 

continue to support ongoing studies of the feasibility and cost of extending transmission 

capacity to high-quality, wind resource areas in Montana and elsewhere that offer geographic 

diversity, better capacity factors and better coincidence to loads. Investments by BPA and other 

Northwest transmission providers may be justified. 

ACTION 10: By July 2008, using the analytical tools of Action 4 and building on the 

results of the Rocky Mountain Area Transmission Study (RMATS), NTAC should work 

with Columbia Grid, NTTG, wind developers and other interested parties to evaluate 

approaches to delivering wind energy from Montana such as an upgrade of Montana’s 

500kV system and evaluate opportunities to deliver wind energy from other isolated wind 

resource areas. 

39
IV. Wind integration cost recovery 

The emergence of wind energy as a significant resource on the Northwest transmission grid 

raises new cost recovery and allocation issues. Historically, most of the variability in control 

area operations has been associated with loads, since the output of most conventional 

generating resources varies little across the course of a scheduling hour except to meet 

variations in load. When the Federal Energy Regulatory Commission (FERC) developed its 

Open Access Transmission Tariff (OATT), it created provisions that allocate the costs of 

regulating reserves (operating reserves) only to the loads within each control area. Neither the 

FERC Tariff, nor any filed tariffs, allocate regulation costs to individual loads based upon their 

individual contributions to control area regulation requirements.19 As a result, control areas do 

not have tariff provisions or rates to charge generators or any individual entities (loads or 

generators) for the variability they may place on the system. 

As discussed in previous sections of this report, the variability and uncertainty of wind energy 

increases the demand for operating reserves required to maintain control area reliability. Yet 

because of the tariff and rate design issues referenced above, loads currently pay for the costs 

of additional operating reserves required to integrate wind. If a utility is purchasing the output 

of a wind project for its own native load service, this may not require any changes to the 

utility’s tariff or rate structure, as long as the costs can be appropriately quantified and 

recovered, although there may be allocation issues among classes of customers. 

However, when a wind project interconnects into one control area, but serves the loads of 

another control area, the loads within the host control area still bear the costs of any additional 

operating reserves necessary to integrate the wind project. In some cases, agreements such as 

dynamic scheduling have been negotiated between the host control area and the control area 

served by the wind plant. These permit the costs of regulation and load following to be born by 

customers in the control area served by the wind plant. However, absent such arrangements, 

current tariffs and rate structures do not ensure that entities creating the demand for additional 

operating reserves are the ones paying for the services. 

 

Although cost recovery and allocation is a threshold issue for each control area, some will 

likely choose to revise their tariff and rate schedules to better align costs and benefits and 

protect the economic interests and statutory rights of their native load customers. At the same

time, there should be a defensible basis for determining any additional within-hour balancing 

requirements resulting from interconnected wind resources. Several participants in this project 

have emphasized that any such tariff or rate changes should be accomplished in a fashion that 

is consistent with principles of cost causation. Moreover, there is no consensus about the point 

at which these costs warrant developing a new tariff, and how that tariff should be designed 

and applied. Given the large number of control areas in the Northwest, there is no single 

answer to these questions. 

For BPA, this threshold has clearly been reached. By the end of 2007, there may be 1,500 MW

of wind in the BPA control area, much of it serving nonfederal loads. As a result, in 2007, BPA 

 19 Regulation costs are allocated to loads based upon their energy consumption or demand, not based upon their

variability. 

40
expects to revise its approach to recovering and allocating wind integration costs. Customers 

and other stakeholders will have an opportunity to provide input through formal rate case 

proceedings. Sales of wind integration services will not compromise BPA’s statutory 

obligations to its requirements customers. 

41
V. Regional efforts to reduce integration costs 

Wind integration costs are a function of the supply, demand and resulting market prices for system

flexibility. They can therefore be minimized by reducing the demand for system flexibility from wind 

energy projects and by identifying least-cost options for supplying the needed system flexibility. Some

of the wind integration studies summarized in this report identified the potential for considerable cost 

savings through regional actions on both the demand-side and supply-side of the flexibility equation. 

A regional wind forecasting network 

Wind integration studies performed in the Northwest and in other regions have concluded that wind 

integration costs are highly sensitive to wind forecast accuracy. Wind forecasting technology and 

techniques to integrate forecasts into power system operations continue to improve. A regional wind

forecasting network using multiple monitoring stations may produce better wind forecasts for a 

consolidated group of wind projects, leading to lower integration costs for individual projects. The 

Northwest Wind Integration Forum should evaluate the potential costs and benefits of a regional wind 

forecasting network and develop an implementation plan if the net benefit exceeds the cost. 

ACTION 11: By July 2008, the Northwest Wind Integration Forum should evaluate the 

potential costs and benefits of a regional wind forecasting network and develop an 

implementation plan in the event of a positive assessment.

Control area cooperation and expanded markets for flexibility services 

Many regional investor-owned and public utilities rely primarily on hydroelectric facilities for 

regulation and load following reserves. Because hydro resources are fast, flexible and do not consume 

fossil fuels, they are in many ways ideal economic and environmental sources of flexibility to manage 

the variability of wind energy. However, they are subject to daily, seasonal and nonpower constraints, 

as well as increasing load obligations. 

For example, during the graveyard hours it could be more cost-effective and environmentally 

beneficial to back down thermal resources in the event of a system imbalance, than it is to carry 

downward regulating reserves on hydro projects. As more wind is developed in the region, it will be 

increasingly beneficial to access the sub-hourly maneuverability of other generating resources in the 

system. Demand management strategies can also provide system flexibility and should be further 

explored. 

ACE Diversity Interchange (ADI) 

The Northwest’s 16 separate control areas each are responsible for balancing their own loads 

and resources. Aggregating wind projects into larger control areas can reduce the amount of 

balancing capacity needed to integrate wind by affecting both the diversity of the wind 

generation and relative penetration levels. To date, control area cooperation, rather than control 

area consolidation has been the rule in the Northwest. Through the Northwest Power Pool, 

control areas share responsibility for contingency reserves and thereby reduce the overall 

contingency reserve requirement. Another method of control area cooperation, known as Area 

Control Error Diversity Interchange (ADI), is under development by the Northwest Power Pool 

42
and being expedited on a pilot basis by several Northwest utilities. Through ADI, participating 

utilities will share Area Control Error (ACE), which may reduce the amount of 

regulating reserves each of the individual utilities must carry. Though the incremental demand 

for regulating reserves from wind energy is quite small, if successful, ADI may take a small 

bite out of the costs of wind integration as well.

The participating utilities have demonstrated an admirable spirit of cooperation and dedication 

to solving the technical issues associated with ACE Diversity Interchange. To create greater 

awareness of this initiative, in July 2007, the participants in the ACE Diversity Interchange 

pilot should provide a progress report to the Steering Committee of the Northwest Wind 

Integration Forum. 

ACTION 12: By July 2007, the participants in the ACE Diversity Interchange pilot should 

provide a progress report to the Steering Committee of the Northwest Wind Integration Forum. 

Expanded markets for flexibility services 

Lessons learned from the ACE Diversity initiative may help expand the availability of other control 

area balancing services that can effectively pool system flexibility beyond the minute-to-minute time

horizon of regulation. This is an important objective. As discussed in Section I, the variability of wind 

(and control area operations in general) is larger across the 10-minute to 60-minute time horizon than it 

is across the regulation time horizon. Wind variability in this timeframe is responsible for a majority of 

wind integration costs and therefore represents the greatest area for potential cost savings. 

Services designed to provide additional flexibility across the within-hour time horizon include 

Supplemental Automatic Generation Control (AGC) and Dynamic Scheduling. These products and 

their variants allow one utility to take on a portion of the within-hour balancing requirements for 

another utility’s control area. 

Through the provision of Supplemental AGC, one entity (control area operator or independent power 

producer) sells a contractually defined amount of generation flexibility (either unidirectional or bidirectional) to assist a control area in managing its within-hour system variability. Dynamic 

Scheduling effectively moves the output of a load or generating resource from one control area to 

another. Other products, such as storage and shaping services, can help manage hour-to-hour wind 

variability. 

The market for control area services and storage and shaping products is very limited. NorthWestern 

Energy knows this from direct experience. In an effort to purchase additional control area services to 

manage the 135 MW Judith Gap wind project, NorthWestern has run several solicitation processes and 

found a very small number of sellers. In 2005, BPA placed a moratorium on the sale of its wind 

integration services, and Grant County PUD is not offering storage and shaping services to new 

customers. 

The Technical Work Group explored the root causes of the limited activity in the market for flexibility 

services, and identified several important barriers: 

1) There are no formal markets or standard product descriptions for wind integration services; 

43
2) Supplemental AGC and Dynamic Scheduling products require firm transmission -

sometimes in both directions – which add significantly to the costs of balancing services; 

3) There is limited dynamic scheduling capability across the Northern and Southern Interties. 

This limits access to the within-hour balancing capability of resources in Canada and 

California. According to BPA, there are substantial technical barriers to expanding this 

capability while reliably managing the grid; 

4) Responsibility for developing and offering flexibility products often lies with the merchant 

(marketing) functions of the utilities. Marketing entities might not have the necessary 

product understanding, risk appetite or pricing capability to develop and offer these 

services; 

5) Some utilities may be unwilling to sell flexibility from their systems because they are 

concerned that they will need the flexibility for their own future needs such as meeting 

Renewable Portfolio Standard (RPS) requirements. In BPA’s case, uncertainty about the 

outcome of the current Biological Opinion remand process and future resource adequacy 

requirements led to the moratorium on new sales of wind integration services; and 

6) Biological requirements and other periodic system constraints limit contract lengths and 

require some utilities to require call-back provisions on any marketed flexibility. 

These barriers present a timely and important challenge, because the potential benefits of robust 

markets for these services are numerous. A more robust marketplace for flexibility services would:

1) Leverage the daily and seasonal differences in system flexibility among the region’s 

utilities, and allow utilities to access a supply of lower-cost flexibility when their own 

systems are facing constraints; 

2) Through dynamic scheduling, allow two or more utilities to exchange the balancing 

requirements for a portion of the wind in their different systems – in effect leveraging the 

geographical diversity of their respective projects into lower individual balancing 

requirements; 

3) Allow more control areas to integrate more wind, thus expanding the geographical diversity 

of the region’s wind fleet; 

4) Provide risk management tools to wind developers who are active participants in the 

wholesale marketplace; 

5) Allow independent power producers to generate additional income by monetizing the 

flexibility characteristics of their assets; 

6) Create price signals for innovative demand management strategies; 

7) Further reduce the probability of having to limit wind generation output during periods of 

hydro constraints; and 

8) Access some of the benefits of shorter-term markets without fundamental changes to the 

existing Northwest market structure. 

Standardized bilateral markets for flexibility services should lower wind integration costs and could be 

developed as an extension of the region’s current wholesale power markets. For example, a hydrodependent utility facing nighttime operating constraints could purchase a block of off-peak 

Supplemental AGC from one thermal-based utility, while simultaneously selling a block of peak hour 

AGC to another. These services could trade in hourly, daily, monthly and seasonal blocks under 

44
standard commercial terms and conditions – without departing from the basic market structure in the 

Northwest. 

To achieve these objectives, multiple regional parties with access to regulation, load following and 

shaping resources will have to participate actively in the marketplace for flexibility services. For some, 

expanded markets for such services will represent a long-awaited opportunity. For others, it will 

require a change in business strategy from an almost exclusive focus on energy marketing to more

active participation in the capacity marketplace. With appropriate risk management policies and 

commercial terms and conditions, such a strategy has the potential to increase wholesale revenues. 

This topic will be the subject of rigorous follow-on discussion by the Northwest Wind Integration 

Forum.

ACTION 13: By the end of 2007, the Northwest Wind Integration Forum should systematically 

address the transmission, scheduling, product design, demand management, regulatory, 

contractual and cost-recovery barriers to expanding the market for flexibility products and 

services. As part of this process, BPA will explore and report on the feasibility of expediting 

relief from dynamic scheduling limits on interties to other control areas. 

 

The future of system flexibility in a carbon-constrained world 

Since the Council released its Fifth Power Plan, issues surrounding the problems of greenhouse 

gas and related climate change have gained considerable attention. During the time this Action 

Plan was being prepared, new and potentially far-reaching legislation has been introduced both 

nationally and at the state level within the region. In some cases, such as the passage of 

Initiative I-937 in Washington, and the proposed “25 percent by 2025” renewables requirement 

in Oregon, these measures may push wind development in excess of what the Council called 

for in its Fifth Power Plan. In other cases, such as the Washington Governor’s Executive Order 

07-02, these proposals call for the reduction of greenhouse gas emissions from historic levels, 

and may create limitations for the use of thermal resources to integrate wind. 

In a carbon-constrained environment, the discussion over maintaining or enhancing hydro 

system flexibility is not limited to its historic scope, or one that can simply be reduced to a 

willingness to pay. Rather, it will become a discussion that also involves trade-offs between 

potential fish impacts and the ability to provide real reductions in greenhouse gas emissions – 

through the ability of wind to displace thermal resource generation and associated emissions to 

the maximum extent possible. While that work is beyond the current scope of this effort, this 

group believes that this is a dialogue that must commence within the region. 

In recognition of the potential for wind power integration to adversely impact fish operations, 

the Council, in Action GEN-9 of its Fifth Power Plan, calls for an assessment of the effects of 

“shaping”20 large amounts of wind power on other hydropower system operations. The purpose 

of the Council’s recommendation is to ensure that the use of the hydropower system for 

integrating wind power does not adversely affect other hydropower system operations. 

Accomplishment of Action GEN-9 will enable further analysis of environmental tradeoffs

 20 The term “shaping”, as used in the Fifth Power Plan, refers to the full array of integration services including

regulation, load following and storage and shaping. 

45
between maintained or enhanced hydro system flexibility and potential fish impacts compared 

to increased reliance upon gas generation and its associated environmental and regulatory 

impacts related to greenhouse gas emissions. The Council should report its findings with 

respect to GEN-9 to the Northwest Wind Integration Forum, which may chose to pursue further 

analysis. 

In addition to this analysis, this Action Plan recommends evaluating the potential applications for other 

existing and emerging technologies including pumped hydro, compressed air storage, batteries, and 

demand management. A more detailed, preliminary discussion of several of these technologies and 

their applications is provided in Appendix D. 

 

ACTION 14: By the end of 2008, the Northwest Wind Integration Forum should sponsor an 

effort to further characterize options for augmenting system flexibility. These should include 

demand-side options, power generation technologies and storage and fuel synthesis technologies. 

The Northwest Power and Conservation Council should complete Action GEN-9 of the Fifth 

Power Plan to improve understanding of the tradeoffs between competing uses of system 

flexibility and report results to the Forum. The Forum may undertake further analysis at that 

time. 

Maximizing the economic and environmental value of wind through regional 

resource planning 

As discussed at length in this report, maximizing the economic and environmental value of wind 

energy involves a tradeoff between busbar costs, operational integration costs, transmission expansion 

costs, and the value of lost energy from “spilling” wind. 

Access to geographically diverse wind regimes may lower operational integration costs and create

access to projects with high capacity factors, but it may come at the cost of transmission investment. In 

deciding how much transmission capacity to build for wind there will be a tradeoff between the cost of 

a new line and the potential for having to redispatch or “spill” some wind in the event of transmission 

congestion. 

New storage technologies may enter into the equation by storing wind energy during periods of 

transmission congestion and/or shape it into more valuable time periods. As the region looks towards a 

future with increasing amounts of wind energy, it will be beneficial to weigh the economic tradeoffs 

between these variables through integrated resource planning at the regional and individual utility 

level. 

The Northwest Power and Conservation Council should seek a planning framework in its next power 

plan to maximize the economic and environmental value of wind energy. It can do so by optimizing 

the tradeoffs between transmission expansion and geographic diversification of wind power, and added 

system flexibility. In conducting this planning, the Council, other regional organizations, and 

individual utilities can draw on the Northwest wind integration supply curve, the high-resolution 

Northwest wind power data set, transmission planning to be conducted by Columbia Grid, Northern 

46
Tier and NTAC, improved information regarding flexibility augmentation options and better 

understanding of the tradeoffs between demands for system flexibility. 

ACTION 15: The Northwest Power and Conservation Council should seek a planning 

framework in its Sixth Power Plan to maximize the economic and environmental value of wind 

energy by optimizing the tradeoffs between transmission expansion, geographic diversification of 

wind power, and added system flexibility. 

Regional coordination of next steps 

Coordination among utilities, to realize the benefits of a variable and relatively low-capacity 

factor renewable resource, has a distinguished history in the Pacific Northwest. Both the 

Pacific Northwest Coordination Agreement (PNCA) and the Columbia River Treaty brought 

the benefits of hydro generation diversity and energy storage sharing to the region. Those 

benefits were used to help finance construction of the Pacific NW-SW transmission intertie. 

Regional coordination of wind resources can net similar savings and benefits. 

Successful implementation of this Action Plan calls for a considerable amount of work over the 

next several years, much of it requiring regional collaboration and coordination. Recognizing 

the timeliness and importance of this work, the Steering Committee has endorsed the formation 

of a Northwest Wind Integration Forum to monitor, facilitate, and review implementation of 

the actions called for in this Plan. As a result, our final recommended action: 

ACTION 16: The Northwest Power and Conservation Council, working with BPA and other 

interested organizations, should establish a Northwest Wind Integration Forum. The purpose of 

the Forum should be to monitor, facilitate and review implementation of the actions called for in 

this Plan. A Steering Committee, initially comprised of the members of the Policy Steering 

Committee of the Wind Integration Action Plan, should oversee the work of the Forum. A Core 

Analytical Team, comprised of technical staff from utilities, regulatory agencies, public interest 

organizations and others, should conduct technical analysis and provide analytical support to the 

organizations charged with implementing Action Plan items. The Steering Committee should 

meet once every six months to review and guide the work of the Core Analytical Team. Activities 

directly undertaken by the Forum should be funded by contributions from participating 

organizations. The Forum should be chartered as soon as practicable following issuance of this 

Action Plan for an initial period of two years. 

47
VI. Complete list of Action Plan items 

ACTION 1: By July 2007, the Northwest Resource Adequacy Forum (NWRA Forum) should 

reassess its 15 percent pilot sustained wind capacity value using currently available data on 

wind plant operation during periods of peak load. In 2008, the NWRA Forum should further 

refine the sustained peaking capacity value of wind power using the improved wind resource 

data set of Action 3 and other available data. 

ACTION 2: Utilities participating in the Northwest Wind Integration Forum should continue to 

refine their study methodologies and estimates of wind integration costs using a robust 

stakeholder input process. They should also estimate the potential for reducing the cost and 

extending the supply of wind integration services through control area cooperation, more active 

markets for within-hour balancing services and other strategies. 

ACTION 3: The Northwest Wind Integration Forum should contract for the development of a 

high-resolution chronological wind resource data set for the Pacific Northwest. The data set 

should be available by December 2007. 

ACTION 4: By September 2007 the Northwest Transmission Assessment Committee (NTAC) 

should propose a formal technical transmission planning methodology for regional wind 

development. This methodology should identify the data requirements and capacity and energy 

planning tools needed to identify the optimal level of transmission investment needed to 

efficiently serve future wind development. 

ACTION 5: By the end of 2007, Columbia Grid and the Northern Tier Transmission Group 

should convene a joint session to begin applying the transmission planning methodology for 

regional wind produced by the NTAC organization. 

ACTION 6: By the end of 2007, the four state regulatory commissions should review and 

commence to amend as necessary, regulatory policies to remove barriers to more efficient use 

of transmission for wind and other renewable resource development. To the extent feasible, 

policies should be consistent across states. 

ACTION 7: BPA should continue development of mechanisms to promote greater utilization of 

the transmission system, including more active reassignments of firm transmission rights, a 

conditional firm transmission product, and voluntary, multiparty economic redispatch 

mechanisms. BPA should report the results of these efforts to the Northwest Wind Integration 

Forum so that other transmission providers might benefit from this experience. The program, if 

successful, can be applied to integrating wind power from other transmission-constrained wind 

resource areas such as Montana. 

ACTION 8: By the end of 2008, BPA should work with regional stakeholders to complete 

plans of service for the proposed West of McNary Phase 1 and West of McNary Phase 2, the I5 Corridor, and North and South Cross-Cascades transmission reinforcements with priority 

given to the I-5 Corridor and West of McNary projects. To the extent available, the plans of 

service should identify preferred upgrades using the capacity and energy transmission planning 

tools called for in Actions 4 and 5. The plans should include the estimated cost and the amount 

of commercially viable ATC for each upgrade. Upon completion, the plans and business cases 

should be reviewed by BPA’s Infrastructure Review Committee. 

48
ACTION 9: By the end of 2007, BPA should work with regional stakeholders to develop a 

generally applicable model for financing market-driven reinforcements and expansions of its 

transmission system using the proposed West of McNary project as a prototype application. 

ACTION 10: By July 2008, using the analytical tools of Action 4 and building on the results of 

the Rocky Mountain Area Transmission Study (RMATS), NTAC should work with Columbia 

Grid, NTTG, wind developers and other interested parties to evaluate approaches to delivering 

wind energy from Montana, such as an upgrade of Montana’s 500kV system and evaluate 

opportunities to deliver wind energy from other isolated wind resource areas. 

ACTION 11: By July 2008, the Northwest Wind Integration Forum should evaluate the 

potential costs and benefits of a regional wind forecasting network, and develop an 

implementation plan in the event of a positive assessment. 

ACTION 12: By July 2007, the participants in the ACE Diversity Interchange pilot should 

provide a progress report to the Steering Committee of the Northwest Wind Integration Forum. 

ACTION 13: By the end of 2007, the Northwest Wind Integration Forum should systematically 

address the transmission, scheduling, product design, demand management, regulatory, 

contractual and cost-recovery barriers to expanding the market for flexibility products and 

services. As part of this process, BPA should explore and report on the feasibility of expediting 

relief from dynamic scheduling limits on interties to other control areas. 

ACTION 14: By the end of 2008, the Northwest Wind Integration Forum should sponsor an 

effort to further characterize options for augmenting system flexibility. These should include 

demand-side options, power generation technologies and storage and fuel synthesis 

technologies. The Northwest Power and Conservation Council should complete Action GEN-9 

of the Fifth Power Plan to improve understanding of the tradeoffs between competing uses of 

system flexibility and report results to the Forum. The Forum may undertake further analysis at 

that time. 

ACTION 15: The Northwest Power and Conservation Council should seek a planning 

framework in its Sixth Power Plan to maximize the economic and environmental value of wind 

energy by optimizing the tradeoffs between transmission expansion, geographic diversification 

of wind power, and added system flexibility. 

ACTION 16: The Northwest Power and Conservation Council, working with BPA and other 

interested organizations, should establish a Northwest Wind Integration Forum. The purpose of 

the Forum should be to monitor, facilitate and review implementation of the actions called for 

in this Plan. A Steering Committee, initially comprised of the members of the Policy Steering 

Committee of the Wind Integration Action Plan, should oversee the work of the Forum. A Core 

Analytical Team comprised of technical staff from utilities, regulatory agencies, public interest

organizations and others, should conduct technical analysis and provide analytical support to 

the organizations charged with implementing Action Plan items. The Steering Committee 

should meet once every six months to review and guide the work of the Core Analytical Team. 

Activities directly undertaken by the Forum should be funded by contributions from

participating organizations. The Forum should be chartered as soon as practicable following 

issuance of this Action Plan for an initial period of two years. 

49
Glossary 

ACE, Area Control Error: A measure (in MW) of the moment-to-moment load resource 

balance within a control area. Technically, ACE measures the instantaneous difference in 

scheduled and actual system frequency and a Control Area’s scheduled and actual interchanges 

with other control areas. 

ADI, ACE Diversity Interchange: Coordination among multiple control areas to relax the 

control needed to balance load, interchange, and generation compared with isolated operations. 

Relaxed control can be achieved because of the sign diversity (some are net positive or overgenerating relative to load and some are net negative or under-generating relative to load) among 

area control errors of the participating control areas. 

AGC, Automatic Generation Control: Generation equipment that automatically responds to changes 

in system frequency in order to maintain target system frequency (60 cycles per second in the US) and/or 

the established interchange with other control areas within predetermined limits. 

ATC, Available Transmission capacity: The amount of marketable transmission capacity on a defined 

transmission path after accounting for existing contractual obligations and operating margins. 

Busbar: The point at which power from a generating resource is first delivered to the high-voltage grid. 

Busbar costs are calculated before considering the costs of transmitting power to load.

Capacity Factor: A measure of the actual annual energy output of a generating resource divided by the 

theoretical maximum output, if the machine were running at its rated capacity during all 8,760 hours of a 

year.

Capacity Value: A measure of the amount of additional peak load that can be served by a generating 

resource without degrading system reliability. For example, a 100 MW wind project with a demonstrated 

15 percent capacity value could reliably serve an additional 15 MW of peak load. 

Control Area: An electric system or systems, bounded by interconnection metering and telemetry, 

capable of controlling generation to maintain its interchange schedule with other control areas, and 

contributing to frequency regulation of the Interconnection. (Also referred to as “Balancing Area” or 

Balancing Authority”). 

CPS, Control Performance Standard: A metric used by the North American Electric Reliability 

Council (NERC) to evaluate the performance of control areas. CPS2 requires that 95 percent of 

imbalances between generation and load above a certain threshold be rectified within 10 minutes. 

Dynamic Performance: The extent to which a generating resource or other element can help support 

grid stability during periods of system disturbance such as a voltage drop. 

Flow Gate: A point in the transmission system defined as a grouping of one or more transmission lines, 

used to measure power flow, usually defined when there is limited capacity across a portion of the

transmission system. 

LGIA, Large Generator Interconnection Agreement: The Federal Energy Regulatory Commission’s 

standardized interconnection agreement for generating resources greater than 20 MW that proscribes a 

50
process for review of interconnection requests and a standard contract format. Created by FERC Order 

2003A. 

Load Following: The deployment of flexible generating resources (or demand-side options) to adjust to 

changes in loads across the 10-60 minute and longer time horizon. Load following is not technically a 

type of operating reserve, but as a within-hour service, it is provided between system basepoint 

adjustments and therefore requires capacity to be reserved from the marketplace given the block-hourly 

markets in place in the Northwest. 

OATT, Open Access Transmission Tariff: The Federal Energy Regulatory Commission Tariff 

defining the requirements for the provision of nondiscriminatory wholesale electrical transmission 

service. 

Operating Reserves: As defined by WECC, the sum of Regulation reserves and Contingency reserves, 

both spinning and nonspinning, As used in this report, operating reserves include the generation capacity 

needed to follow moment-to-moment changes in loads and wind (regulation) and longer-term (10-60 

minute) changes in loads and wind (load following). As used in this report, operating reserves do not 

include capacity used to shape the output of wind projects over diurnal or seasonal periods. 

OTC, Operating Transmission Capacity: The total transmission capacity of a line or group of lines 

(flow gate) after setting aside a margin for reliability and noncontract flows. 

POS, Plan of Service: An engineering and economic assessment of the physical infrastructure required 

to interconnect a new resource to the grid or to increase the transfer capacity across a portion of the 

transmission system. 

RAS, Remedial Action Schemes: Protective systems that ensure that corrective actions take place 

immediately following the forced outage of a transmission line or transmission system element. 

Renewable trunk line transmission: A radial transmission line primarily intended to serve multiple 

renewable resource projects located within a common resource area. 

Storage and shaping: The practice of converting the variable hourly output of a resource like wind 

energy into predictable volumes of power for later delivery, sometimes shaped into flat blocks of peak 

and off-peak energy. 

System flexibility: The ability of both supply-side and demand-side resources to respond to changes and 

uncertainties in system conditions. Flexibility also refers to the ability of the hydro system to store water 

for delivery in future time periods. 

Regulation: The deployment of fast, responsive generating capacity to manage moment-to-moment 

changes in the load resource balance of a control area. Regulation is usually provided by units on 

Automatic Generation Control (AGC). 

51
Appendix A. The language of Northwest utility system operations 

The most important objective of an electrical utility is to meet its load obligations in a reliable, 

cost-effective manner. Long-term planners look out into the future and attempt to forecast 

system loads and load variability as well as other variables such as fuel costs, inflation, and 

expected market prices. They then determine which combination of power plants, demand-side 

techniques and market purchases will provide the greatest certainty of meeting peak load at the 

lowest overall cost. In most cases, they choose a combination of power plants with different 

generating characteristics. These include baseload plants with high capital and low operating 

costs, intermediate loaded plants with sufficient flexibility to follow the general trend in hourly 

load variation, and quickly dispatchable and flexible peaking facilities, often with low capital 

costs and high variable costs, designed for operation during periods of peak or super-peak load. 

The long-term resource planner must also ensure that a portion of his generation fleet is capable 

of providing governor response, and operating with Automatic Generation Control to 

maintain appropriate voltages, and to handle changes in load/resource balance across both the 

very short (second-to 10-minute) and intermediate (10-60 minute) time frame. Long-term

resource planners are also concerned with building a sufficient reserve margin of generation 

above and beyond their peak load in order to demonstrate resource adequacy for purposes of 

meeting their peak load obligations.

Planning uses probabilistic models of different portfolios of resources to estimate the reliability 

of the system under different conditions of load and generator availability. The Power Council 

uses an analytical technique, known as Loss of Load Probability (LOLP), to assess the state of 

regional reliability. This type of analysis can also been conducted for wind generation. The 

increment of peak load that can be carried on a probabilistic basis by a generation resource has 

been equated to its capacity contribution or capacity value for the purposes of long-term

planning. 

Long-term transmission planning is conducted for transmission infrastructure requirements, with 

an eye to securing sufficient transfer capacity to move power from points of receipt to points 

of delivery across the transmission grid. 

Power Marketers, Traders and Generation Schedulers (who collectively are referred to as the 

“merchant function” or “load serving entity”) are charged with meeting load and optimizing the 

economic value of the power system that they inherit from the long-term resource planners. They 

conduct this optimization across a range of timeframes, including yearly, seasonal, monthly, 

balance of month, daily, and hourly. Their primary responsibility is to deploy that combination 

of available power plants and market purchases/sales that can meet load and monetize surplus 

generation at the lowest overall cost/highest net value to their organization. These merchants 

have access to several markets to assist in the balancing of their system needs. These include 

forward, day ahead, and hourly “real-time” markets. Trading for future months, while at times 

quite illiquid, is available during several business hours each weekday. Trading of power for 

day-ahead (or Fri/Sat, Sun/Mon, periodic 3-day) is conducted primarily each weekday morning 

from 6:00 a.m. – 7:00 a.m. Electricity trading is conducted primarily for blocks of peak and offA-1
peak energy, although other products, such as super-peak energy, reserves, options, and 

exchanges also are bought and sold. The 24-hour/day hourly real time market for next-hour 

delivery closes 30 minutes prior to the hour of delivery, i.e. trading for the 9:00 a.m. – 10:00 a.m.

time period closes at 8:30 a.m. 

Prior to day-ahead trading, the load serving entity will generate a load forecast and generation 

estimate for each of its power plants to determine a net long or short position going into the next 

day. For systems with wind as part of the generation mix, the entity must also generate a forecast 

of wind generation for the next day. The entity will also develop an estimate of load forecast 

error and wind forecast error as additional factors in determining how much power to buy or 

sell for the next day. Most other power resources, if deemed available, will likely have lower 

forecast errors than wind facilities. 

In the hourly time frame, the generation schedulers and real-time marketers primarily focus on 

meeting hour-to-hour changes in loads by adjusting the basepoints or setpoints of their fleet of 

generation assets and making balancing sales and purchases. The basepoint adjustments, or 

ramps, occur during the 20-minute interval from 10 to until 10 after each hour. Since there are 

no standard markets for within-hour electricity in the Pacific Northwest (the hourly real-time 

market being the shortest duration market available), generation schedulers use their basepoint 

adjustments to position their systems so that units on Automatic Generation Control or with 

fast-ramping capability can ramp up and down during the hour to adjust to the full range of

motion of net system variability until the next basepoint adjustments are made. An estimate of 

wind energy generation for next hour will also be factored into the calculated basepoint

adjustment for the next hour. 

The within-hour timeframe between basepoint adjustments is the domain of the Control Area 

Operator. Control Area Operators are focused exclusively on system reliability. Their principle 

objective is to manage the frequency of the control area at 60 cycles (Hz) per second. To 

accomplish this, Control Area Operators must ensure that the system is carrying sufficient 

operating reserves. There are several categories of operating reserves with specific terminology. 

Regulating reserves are carried to manage minute to minute fluctuations in load and resource 

balance. These reserves are provided from spinning units with sufficient bi-directional capability 

to adjust to changes in system balance and minimize the Area Control Error (ACE) of the 

control area. ACE, which is expressed in MW, measures the instantaneous difference in 

scheduled and actual system frequency and a Control Area’s scheduled and actual interchanges 

with other control areas. 

The Control Area Operator must also ensure that the system is carrying sufficient contingency 

reserves to cover unanticipated losses of generation or transmission elements. According to 

Western Electricity Coordinating Council (WECC) requirements, control areas must carry the 

greater of a combination of 5 percent of hydro generation and 7 percent of thermal generation, or 

their most severe single contingency. Half of the required contingency reserves must be on line 

and spinning, the remainder must be able to be brought on line and loaded within a ten minute 

period. The Northwest Power Pool requires 5 percent contingency reserves for wind generation. 

Control areas must also carry sufficient reserves for any scheduled interruptible imports and ondemand obligations that they have. Performance is measured by a set of NERC Control 

A-2
Performance Standards, known as CPS1, CPS2, and a Disturbance Control Standard 

(DCS), which measure an entity’s ability to follow system frequency, regulate load, and recover 

from system disturbances. 

Generators, including wind, may be required submit a generation schedule to the control area’s 

transmission scheduling desk prior to the hour of operation. If a resource deviates from its 

schedule during the hour, it will contribute to variations in net system balance during the hour 

and these variations will be offset by those generation units providing regulating reserves (or 

contingency reserves in the case of a major outage) to the control area. At the end of each hour, 

average hourly positive or negative deviations from schedule, in MWh, are calculated by the 

transmission provider and a financial penalty is assessed to the generator that is subject to 

contract or tariff terms. These penalties include payments by the generator for not meeting a 

schedule, or reduced payments for exceeding the schedule. 

 

A-3
Appendix B. Discussion of study methodologies and preliminary results 

from initial Northwest wind integration studies 

Avista Utilities (2007) 

System overview

Avista Utilities serves a control area that peaks at approximately 2,200 MW during the winter 

months. The company owns or controls a mix of resources (excluding nonhydro contracts) that 

is, on a capacity basis, comprised of approximately 56 percent hydro, 28 percent gas, 11 percent 

coal, and 4 percent nonhydro renewables. The utility presently integrates 35 MW of the Stateline 

Wind facility into its control area. 

Study approach 

Avista’s study builds on analyses completed in 2001-02. A proprietary dispatch model driven by 

a linear programming engine optimizes operations with and without wind variability in the 

utility’s system. This hourly model tracks various capabilities of the control area to meet system

loads at least cost. The model contains three modules: The first optimizes hydro generation on a 

daily basis at the Mid-Columbia and Clark Fork projects, tracking constraints such as maximum 

and minimum storage and generation levels, and minimum flow. The second module creates an 

hourly, day-ahead preschedule that takes daily hydro quantities and allocates them across the 

highest -value hours possible given system constraints. The preschedule model contains dayahead forecasts of load and wind generation. Preschedule purchases and sales made to balance 

system requirements are carried forward to the third, real-time module. The real-time module 

reoptimizes utility resources given updated one- to two-hour ahead forecasts for wind and load. 

It performs a task similar to the preschedule module. 

Avista found the key driver of integration cost to be incremental reserves necessary to accept 

wind. Reserve obligations are calculated using historical data from 2002 through 2004. 

Specifically, regulation (up to 1 minute), load following (1 minute to one hour), spinning and 

nonspinning operating reserves, and forecast error are input into the Avista model as constraints 

on system optimization. In the with-wind variability cases, incremental reserve quantities for 

regulation, load following, and forecast error are added to system obligations in the model. 

Incremental regulation and load following reserves are calculated first by identifying levels 

necessary to meet load variability alone. A second step performs the same analysis, but nets wind 

generation against load when calculating reserve obligations. Reserve levels are increased in the 

with-wind case to ensure similar system operating performance levels as today (CPS1 & CPS2 in 

excess of 95 percent). 

The regulation component was found to be constant across all hours, rising with the level of 

wind added into Avista’s control area. Load following obligations varied both with the level of 

wind in Avista’s control area, and as hourly wind generation levels changed. 

B-1
Forecast error, a product covered by reserving system capability, was a significant focus of the 

Avista study. Two-hour-ahead wind forecasts were compared to actual wind generation levels, 

reduced by a) approximately 25 percent to account for improvements to the forecast made 

possible by using “state-of-the-art” wind forecasting techniques, and b) 15 MW to approximate 

the Company’s present reserve levels carried for error in the load forecast. Forecast error was 

calculated at a 95 percent confidence interval and carried across all hours in the up and down 

directions. 

Wind generation data for 2002 through 2004 calendar years was developed using the Oregon 

State University/BPA 10-minute wind speed database. Data limitations required the analysis to 

focus on the period August 2002 through July 2003. Avista considered various levels of wind 

from 100 MW to 600 MW, or between 5 percent and 30 percent of control area peak demand. 

Wind resources were evaluated in the Columbia Basin, in Eastern Montana, as a 50/50 mix of 

Columbia Basin and Eastern Montana wind, and as a multistate “diversified” mix with many 

smaller sites combined. 

Preliminary Results 

Tables B.1 and B.2 detail total wind integration costs from the Avista study. Eastern Montana 

wind appears to be very expensive to integrate due to its volatile nature. At 10 percent and higher 

penetration levels, the 50/50 mix of Eastern Montana and Columbia Basin wind has equal to 

much lower integration costs than either basin alone at similar penetration rates due to diversity 

benefits. Higher levels of diversity appear to provide additional system benefits. Costs rise 

predictably as wind capacity increases on a system, irrespective of the resource mix considered. 

Table B.1 – Preliminary Avista wind integration cost estimates ($/MWh) 

System Penetration

Basin 5% 10% 20% 30%

Col. Basin $2.75 $7.76 $11.61 $14.95

E. Montana $7.55 $13.01 $19.92 $24.16

50/50 CB/MT $4.01 $6.99 $11.72 $15.09

Diversified $2.85 $3.05 $6.65 $8.84

Table B.2 – Preliminary Avista wind integration cost estimates (percent of market) 

System Penetration

Basin 5% 10% 20% 30%

Col. Basin 5.0% 14.1% 21.2% 27.3%

E. Montana 13.8% 23.7% 36.3% 44.0%

50/50 CB/MT 7.3% 12.7% 21.4% 27.5%

Diversified 5.2% 5.6% 12.1% 16.1%

B-2
Integration costs were very sensitive to absolute market price levels. Where market prices rise or 

fall by 50 percent from today’s levels, integration costs would also be expected to change at a 

similar level. 

Avista’s study broke out integration costs between incremental regulation, load following, and 

forecast error as follows in Table B.3.

Table B.3 – Components of integration, selected cases 

Wind System Wind Wind Reg- Load Forecast

Capacity Penetration Location Shape ulation Following Error

100 MW 5% C.Basin 10.7% 40.9% 37.6% 10.7%

200 MW 10% 50/50 Mix 6.3% 23.1% 46.2% 24.3%

400 MW 20% Diversified 7.5% 25.1% 26.9% 40.5%

600 MW 30% Diversified 5.9% 16.2% 43.9% 33.9%

Avista plans to acquire a diversified wind resource portfolio to keep integration costs as low as 

reasonably possible. To this end, the Company estimates that at a 5 percent penetration level, its 

wind will come from the Columbia Basin. At a 10 percent level, a mix of Columbia Basin and 

Montana wind would be integrated. Above 10 percent, a diversified mix of resources would 

greatly reduce costs when compared to single sites. Avista estimates for wind integration reflect 

this planning assumption. Table B1 above highlights in yellow the Company’s estimate for wind 

integration given its forecasted mix of future wind generation acquisition. Wind integration cost 

estimates are reduced substantially at the higher penetration levels due to wind site diversity. 

Comparison to general study approach adopted by System Operators Committee

Avista’s study, being fairly recent, conforms to the primary integration factors identified in this 

report. 

Bonneville Power Administration (2007) 

Study approach 

The Bonneville Power Administration (BPA) estimated the incremental regulation and load 

following requirements, consistent with the procedure performed by Avista with the exception 

that forecast error was not separated from the load following requirement. For the load following 

component, this methodology derives the distribution of actual machine movement due to the 

combination of load following and forecast error. The regulation requirement was treated as an 

off-the-top obligation. The off-the-top portion of the load following and forecast error 

requirement was calculated as the maximum deviation of the actual combined wind and load 

deviation from forecast. The base case assumed zero wind penetration, therefore regulation and 

load following requirements in this case were to serve existing area load only. The data set used 

B-3
for the regulation analysis consisted of 1-minute average BPA area load and 1-minute average 

wind generation, normalized to the actual wind fleet capacity. The data spanned 

November 4, 2005, to October 29, 2006, inclusive. The load following analysis used the same

data set for the no-wind, and present-day cases, and was scaled up using a two-year period of 

simulated 10-minute average wind generation from work performed by 3Tier. 

Regulation and load following requirements were then passed to various models to simulate the 

Federal Columbia River Power System (FCRPS) response to the additional requirements. The 

Columbia Vista (CV) model, a reservoir network optimization model, was used to assess how the 

detailed operation of the FCRPS changed with increasing reserve requirements, to assess the 

FCRPS’s ability to cope with large deviations from scheduled wind generation, and to 

investigate efficiency-related incremental costs associated with increased wind penetration and 

reserve requirements. 

The CV studies focusing on impacts due to additional reserve requirements used the Short-Term

Vista module. The analysis was deemed “adversely affected” by the additional requirements if 

BPA had to market more than 150 aMW and hydraulic or fishery constraints could not be met. 

Results were deemed “limited concern” if the additional requirements caused BPA to market less 

than 150 aMW, and all hydraulic and fishery constraints were met. Two periods in 2005 and 17 

periods in 2006 were selected for this study from actual planning-level runs. These were re-run 

with additional wind reserve requirements and load forecast uncertainty to assess impacts. 

The ramping studies in CV sought to gain insight to how the FCRPS would react to large, 

unscheduled changes in wind generation, both up and down. The same criteria described in the 

preceding paragraph were used to determine how the FCRPS operation was affected. Eight 

actual planning-level model runs were selected from 2006, and re-run with the wind reserve 

requirements and sudden, nonforecasted ramps to see how system absorbed the impact. Wind 

ramps were tested in 500 MW increments up to 4,000 MW. For each day, ramps were tested 

during the graveyard, morning load pick-up, afternoon/evening peak, and across the evening load 

drops. 

A test version of CV was used to estimate any systemwide changes in efficiency. For this study, 

one week in October 2006 (low flow condition) was analyzed with and without the additional 

wind reserve requirements. Changes in efficiency were determined by examining the simulated 

unit dispatch across the FCRPS resources. 

Changes in the temporal distribution of generation were derived using a 60-year, 

HYDSIM/HOSS study. Results from those simulations were passed to a modified version of the 

RiskMod model to assess any opportunity costs associated with changes in generation. This 

process uses a Monte Carlo approach varying water conditions, market price and depth, load and 

resource availability. 

Last, a frequency study was conducted on hourly wind generation from 2001 to 2006, to assess 

the dependable capacity of the wind fleet to date. 

B-4
Preliminary Results 

The incremental reserve requirements are summarized in Table B.4. 

Table B.4 – Preliminary BPA wind integration cost estimates 

Wind Fleet Capacity 0 MW 733 MW 1000 MW 2000 MW 3000 MW

Wind Penetration (% of Peak Load) 0% 8% 11% 22% 33%

INCREMENTAL REQUIREMENTS

Regulation - 6 10 27 48

Load Following - 19 34 114 211

Contingency Reserve Obligation - 9 13 25 38

Total Incremental Reserve Obligation 0 34 57 166 297

INCREMENTAL COST ($/MWh of Wind Generation) $1.90 $2.40 $3.70 $4.60

The contingency reserve requirement is an average amount taken as 5 percent of the average 

energy production, defined as the wind fleet capacity factor multiplied by the capacity. 

Assuming a 25 percent capacity factor this simplifies to 1.25 percent of the wind fleet capacity. 

The CV studies indicated that the additional reserve requirements result in a general shift of

FCRPS energy production from heavy load hours to light load hours. During periods of high 

stream flow, there was an increase in spill amounts with the additional reserve requirements. The 

model may be violating required operations above roughly 500 MW of additional regulation plus 

load following reserves, unless BPA undertook significant marketing (e.g. 500-1000 MW LLH). 

The ramping studies that looked at the effect of large deviations from forecast wind generation 

indicated the FCRPS is able to accommodate unexpected ramps of the same magnitude as the 

regulation and load following reserve requirements. Ramps were the most difficult to manage 

during the light load hours, over the hour-ending 23:00 load drop, and during periods of high 

flows and spill operations. During other times, large wind ramps could often be accommodated 

without difficulty. 

The efficiency studies showed that in order to accommodate the additional uncertainty and to 

provide enough dynamic capacity to cover the additional reserve requirements, projects generally

needed to put on more units than they otherwise would. This resulted in less efficient use by 

shifting the operating point off of a more optimal level, resulting in an efficiency loss of 

approximately 1 percent. This would equate to a loss of about 37 aMW at Grand Coulee Dam

when loaded at approximately 3,700 MW. This type of study is planned to be expanded to 

determine if the results obtained for the October runs are similar during other times of the year 

and under other operating conditions. A preliminary study with higher flows indicated the 

efficiency loss was significantly less than 1 percent for the given wind penetration levels. This 

likely is due to the fact that higher flows/generation naturally require more units in service, 

which in turn increases available dynamic capacity while still maintaining peak operating 

efficiency. 

B-5
The HYDSIM/HOSS studies reflected the same general shift of energy from the heavy load 

hours to the light load hours. This shift moves energy from high value period to those of 

generally lower value. Periods of low stream flow showed the most dramatic shifts in generation. 

The cost of moving energy from high value periods to lower value periods is not the only reason 

for revenue loss to BPA. Additionally, regulation and load following services tend to move units 

off efficient operating points within the hour, add incremental wear and tear to the units, and may 

require additional cycles of units on and off. 

The cost estimates in Table 4 are based on average costs and prices and assume no other 

competing need for the capacity required to provide regulation and load following. It is 

important to note that many other factors are included in the actual pricing of regulation and load 

following services through the formal rate case process. The cost shown here are representative 

of the added cost of providing more regulation and load following over existing rates for such 

services. 

BPA has found evidence of persistent under/over forecasts of wind generation within the day. 

This may result in additional shifts in energy in addition to that observed for holding reserves. 

This was not captured in the studies described here and may be in addition to the costs presented 

here. 

In addition to less efficient operation of the system, (including the reduced ability to shift hydro 

fuel supplies into more valuable hours) that was considered in the preceding regulation cost 

discussion, there is a need to replace the capacity dedicated to wind integration that had

previously been available to meet federal preference customer load growth. While some parties 

may argue that the recovery of these embedded costs is simply a reallocation of the priority of

the use of the FCRPS, BPA’s perspective is that the FCRPS capacity is presently dedicated to 

future federal load obligations. Therefore if this capacity is committed to wind integration, it 

must be replaced with similar capacity and flexibility to meet future federal load. [Note: This 

statement likely applies to any control area operator that integrates wind using resources that are 

dedicated to meet customer load obligations.] 

Idaho Power (2007) 

System overview

Idaho Power Company serves a control area that peaks at approximately 3,100 MW during the 

summer months. The company relies heavily on hydroelectric power for its generating needs, 

and is one of the nation’s few investor-owned utilities with a predominantly hydroelectric 

generating base. The utility has 3,087 MW of installed generation, comprised of 1,708 MW of 

hydroelectric generation (nameplate capacity) and 1,379 MW of thermal generation. In a typical 

year, 53 percent of Idaho Power’s generation comes from its hydroelectric resources and 47 

percent from its thermal resources. Idaho Power presently integrates 10.5 MW of wind 

generation directly into its system. However, approximately 380 MW of additional wind 

generation under contract is expected to come on-line near the end of 2007. 

B-6
Study approach 

Idaho Power contracted with EnerNex for its wind study completed in December 2006. The 

company used its hydro-optimization software, Vista by Synexus Global, to quantify incremental 

wind reserve costs. Vista’s hourly optimization routine is capable of modeling nonhydroelectric 

generation resources, such as wind and thermal plants. To arrive at wind integration estimates, 

Idaho Power ran Vista with wind in its actual hourly profile, and with wind input in flat daily 

levels having energy equivalent to the actual hourly profile. 

Idaho Power considered the same incremental reserve products as the Avista study, namely 

regulation, load following and forecast error. Its methods of deriving these products also were 

greatly the same, except that load following requirements were not varied hourly with the wind 

forecast. Idaho Power found early in its study that unit commitment costs on their system were 

not significant due to adequate liquidity in the hourly wholesale marketplace; therefore it 

modeled only real-time system operations and not day-ahead scheduling. 

One strength of the Idaho study is its comprehensive look at potential wind locations throughout 

Idaho Power’s service territory. This work represents the first effort by a Northwest utility to 

model its service territory for wind potential. The study developed 5-minute historical data for 

more than 70 wind locations in Idaho Power’s service territory for 1998, 2000 and 2005 to 

represent average, low, and high hydroelectric generation years. This data gave Idaho Power an 

excellent opportunity to consider the benefits of wind diversification. 

Idaho Power considered system wind integration of between 300 MW and 900 MW, which is 10 

percent to 30 percent of control area peak demand. 

Preliminary Results 

Table B.5 presents the results of the Idaho Power study. Idaho evaluated integration costs as a 

percentage of the wholesale marketplace, but “converted” them to a cost per MWh of wind 

integration assuming its PURPA tariff rate. 

Table B.5 – Preliminary results of Idaho power study 

% of Mkt $/MWh *

300 10% 15.5% 9.75

600 20% 18.7% 11.72

900 30% 25.8% 16.16

Wind 

Capacity

Penetration 

Rate

Integration Cost

* assuming a market price of $62.77, Idaho’s current published 

 PURPA avoided cost rate. 

B-7
PacifiCorp (2003/04) 

System overview

PacifiCorp serves two control areas with a coincident peak of approximately 9,400 MW during 

the summer. The company’s resource mix is, on a capacity basis, comprised of approximately 65 

percent thermal resources, 12 percent hydro (including hydro contracts), and 4 percent nonhydro 

renewables. The remainder is purchased power. 

The utility currently integrates approximately 600 MW of wind resources (owned, purchased and 

managed for others) into its control areas. 

Study approach 

PacifiCorp first published integration estimates around the time of its 2003 Integrated Resource 

Plan. This study was ground-breaking in the Northwest, as no utility had to that point attempted 

to quantify integration costs. The original work was updated and published for its 2004 IRP. 

The study evaluated incremental hour-to-hour operating reserve and system balancing costs 

associated with wind variability. PacifiCorp calculated the fractional incremental operating 

reserves necessary to integrate wind as the incremental load/wind combined variability computed 

on an hourly integrated basis. The fractional incremental reserve requirement was calculated by 

comparing the dynamic range of 1) the utility’s integrated hourly load and 2) the utility’s 

integrated hourly load where integrated hourly wind generation was netted against it. The 

fractional incremental requirement was taken to be the standard deviation of the combined 

system divided by the standard deviation of the load by itself. 

System balancing costs were defined as the additional operation expenses incurred as a result of 

adding wind generation into its system, examples of which were incremental: market sales and 

purchases, unit start-ups, dispatching of reserve-capable units, and off-optimum operating points 

for thermal plants. PacifiCorp used the Global Energy Decisions’ MarketSym system dispatch 

model to estimate the balancing costs between scenarios where flat block of energy were 

integrated, versus similar average energy amounts integrated using varying wind shapes. The 

difference in operating costs between with and without wind studies were taken to represent the 

additional operating costs due to wind on the system. 

PacifiCorp reviewed three future years over five wind penetration scenarios approaching 2,000 

MW in its study. Wind data for PacifiCorp’s study was developed using actual wind site data 

from its system where possible, supplemented with request-for-proposal data. These data were 

scaled up for high-penetration scenarios, by lagging the available data sets by one or two hours 

in each direction. 

Preliminary results 

PacifiCorp evaluated penetration levels on its system from 5 percent to 20 percent in its control 

area. The figures are presented in Table B.6 

B-8
Table B.6 – Preliminary results of PacifiCorp study 

Penetration Level Wind Integration Cost 

5% $1.86/MWh 

10% $3.19/MWh 

20% $5.94/MWh 

All figures are in 2006 dollars. 

Puget Sound Energy (2003/05) 

System overview

Puget Sound Energy (PSE) serves a control area that peaks at approximately 4,650 MW during 

the winter months. The company’s resource mix is, on average energy basis, comprised of 

approximately 28 percent hydro, 17 percent gas, 22 percent coal, and 5 percent wind. The 

remainder is made up of contracts and market purchases. PSE currently owns 370 MW of wind 

resources, and integrates 220 MW in its control area.

Study approach 

Puget Sound Energy (PSE) commissioned a multiphased study to estimate wind integration costs 

for 25 MW to 450 MW of wind capacity (0.5 percent to 10 percent of system peak demand). PSE 

worked with Golden Energy Services, Inc., and jointly developed analytical models that reflected 

actual operating conditions and estimate PSE’s wind integration costs. The models considered 

operations-based hydro routing, balancing all reserve obligations with Mid-C contract resources 

and the wholesale marketplace, Mid-C generation constraints and option cost of reserving a 

portion of Mid-C storage to integrate wind resources. 

Phase 1 results from 2003 were not publicly released. However, Phase 2 published results 

provide a summary of Phase 1 results and methodologies. The Phase 2 report is contained in 

Appendix J of PSE’s 2005 IRP. Since the completion of the Phase 2 report, additional analyses 

have been underway to incorporate new operational data. 

The PSE study evaluated incremental regulation, operating reserve, and forecast error costs due 

to incremental additions of wind at differing levels of Mid-C capacity. PSE estimated that 

incremental regulation obligations were small. The study relied on several technical papers on 

regulation requirements at Mid-West wind farms due to a lack of Northwest data. Operating 

reserves were calculated as 5 percent of on-line wind generation, in line with NWPP operating 

reserve policies. For the Phase 1 study, PSE determined that incremental regulation would be 

only 1 MW on the PSE control system for a 154.5 MW wind farm. 

Forecast errors were evaluated for the hour-ahead and day-ahead time periods. The hour-ahead 

forecast error was calculated using a 95 percent confidence level given the illiquidity of the intraB-9
hour marketplace for system balancing. Day-ahead reserves were calculated at a 75 percent 

confidence level, based on PSE’s expected ability to correct day-ahead imbalances in the realtime marketplace. As additional operating data becomes available and forecasting techniques 

improve, wind forecast are expected to improve. PSE also evaluated the sensitivity of wind 

integration cost with incremental improvements in the hour-ahead and day-ahead forecasts. 

Preliminary results 

The PSE Phase 2 study found wind integration costs to be flat across the 0–10 percent wind 

penetration level. Regulation costs were estimated at $0.16 per MWh. Operating reserves created 

no incremental cost relative to the addition of nonwind resources. Day-ahead forecast error was 

essentially flat between $0.82 and $0.89 per MWh of integrated wind. Hour-ahead forecast error 

was the largest contributor to wind integration, equaling between $2.72 per MWh at 0.5 percent 

system penetration (of peak load) and $3.01 per MWh at a 10 percent penetration. Total 

integration cost over the 25 MW to 450 MW range was $3.73 to $4.06 per MWh. PSE found that 

integration costs are highly sensitive to the relationship of on- to off-peak prices and to hydro 

conditions. 

B-10
Appendix C. Technical requirements and cost estimate for development of

a Northwest chronological wind data set 

Because of the need to think regionally about wind integration in the Northwest, a cooperative approach 

to securing a high-quality data set is proposed. This data set will be created from a large meteorological 

model, called a mesoscale meteorological model. This modeling can recreate the weather at any point in 

time and space, and can be used to construct detailed chronological wind speed and wind power data that 

represents wind generation in the region. The mesoscale modeling suggested below can be improved and 

informed by some existing wind data that has been offered for use by BPA (existing wind plants), PPM 

(existing wind generation), and Avista. Although these data cannot adequately represent the wind 

penetration to be investigated by the Northwest Wind Integration Forum (NWIF), they can be used to 

statistically correct the mesomodel output, increasing the accuracy of the simulated wind data sets. 

1. The NWIF intends to engage a firm (or firms) that can create 10-minute wind speed data using 

meso-scale weather models in the areas of potential wind development in the Northwest. The 

data set would ideally be three years long, and should represent the load shapes of the years that 

will be used in the NWIF analysis. Because of the significant hydro generation resources in the 

area, the three-year period selected may represent high, median and low water years. Average 

wind-speed every 10 minutes and at a 4km-square grid (minimum) for the Northwest would be 

simulated. Geographic areas within the footprint where wind development is likely to occur 

should be modeled at a higher-resolution grid, potentially as low as 1 km-square. However, the 

geographic resolution selected may also depend on the terrain, based on the judgment of the 

modeling team. 

2. The data series should adequately represent the geographic dispersion impacts of the various 

wind scenarios. For one or more scenarios (determined by the project participants and budget) 

virtual anemometer data would be used to calculate power output in a way that would represent 

real wind plant output. This implies some limit to the wind capacity that could be represented by 

a single grid point, to be determined by the modeling team and the relevant geographical features 

of the region. 

3. The region will include most of Washington, Oregon, Idaho and most of western Montana. Small 

portions of western Wyoming, northern Utah, northern Nevada and northern California may also 

be included. The specific details will be determined jointly by the project team and may be 

subject to budget. 

4. The project team will include individuals involved with the mesoscale meteorological 

simulations, members of the Data Committee of the NWIF, and members of the funding 

organizations. 

5. The anticipated cost of the simulation is expected to be between $300,000 and $750,000, 

depending on technical details and scope of the geographic footprint, and the number of 

extraction points (virtual anemometers). This cost range would cover a three-year data set. 

6. The approximate elapsed time to provide this three-year data set is approximately two and a half 

months to six months from execution of the project. 

C-1
Appendix D. Other supply and demand-side flexibility technologies 

Pumped storage and compressed air technologies

Pumped storage has many appealing characteristics for a system with high wind penetration. It can 

provide a full range of ancillary services, such as regulation and load following. It can provide a source 

of load during off-peak hours, shape wind energy into more valuable peak hours, and help manage grid 

congestion when transmission lines get heavily loaded. 

Although pumped storage has high capital and operating costs, which are difficult to recover given price 

patterns in the Northwest, wind storage during off-peak hours could help compensate for the limitations 

on hydro system flexibility at night. Also, storage can add additional capacity and economic value to 

wind resources. There are many pumped storage facilities in operation around the country, including the 

250-MW facility at Grand Coulee Dam. Compressed air storage technology is less commercially 

advanced, but should be able to provide the same basic services as pumped hydro storage. 

California’s Lake Elsinore pumped hydro storage facility: California is considering a new pumped 

storage facility at Lake Elsinore in the southern part of the Los Angeles basin. The project has an 

estimated price tag of $1 billion to $1.3 billion for 500 MW of capacity, and it is stirring lively debate 

about its economic merits. The facility, which would pump water into a large reservoir behind a 180-foot 

high dam in the Cleveland National Forest, is being proposed as a source of off-peak storage and 

operating reserves for the state’s rapidly growing fleet of wind and solar projects. Mike Florio, a 

regulatory lawyer and consumer advocate with the Utility Reform Network, was quoted earlier in 2006 

describing the project’s sizeable price tag as reasonable and “fairly realistic.”21 The California ISO is 

squarely behind the project so it appears to have some chance of proceeding. If so, it will provide a 

valuable test case and some useful lessons about cost-effectiveness along the way. The operating 

economics of this project will be particularly interesting, including losses associated with the pumping 

process. 

Iowa Stored Energy Plant: The Iowa Stored Energy Project, with potential financial backing from the 

Iowa Public Power Agency, is a proposed compressed air facility designed to store off-peak wind 

generation for later delivery during peak periods. The facility would compress air in a cavern formally 

used for natural gas storage. The facility would use off-peak electricity to power a motor/generator that

drives compressors to force air into an underground storage reservoir. During peak load periods, the 

compressed air would be returned to the surface, heated by natural gas in combustors and run through 

high-pressure and low-pressure expanders to power a motor/generator to produce electricity. Developed 

specifically to store the energy of wind projects, the facility has a current cost estimate of $160 million 

for a 200 MW capacity facility ($800/kW). No information is currently available on marginal operating 

costs. Project sponsors are aiming for a 2011 construction date. DOE has been a major sponsor of the 

effort. 

Of note, Southwestern Public Service (Xcel) in Texas recently worked with a company called Ridge 

 21 The Californian (North County Times), March 8, 2006. 

D-1
D-2

Energy Storage and Grid Services to explore the value of compressed air technology as a method of 

mitigating transmission congestion associated with the high concentration of wind projects in West 

Texas. Although this Action Plan did not explore this project in detail, it presents an interesting 

conceptual approach to transmission planning and asset management in a high-wind penetration 

environment. 

Smart grid technologies - the next frontier

During the last 12 to 18 months, there has been a flood of venture capital and R&D money into 

new “smart grid” technologies. These include Vanadium Redux Flow Batteries and sophisticated 

demand-side methods for cycling loads. Few of these technologies are commercially viable at the 

moment, but some of them, such as flywheels – which are now being tested as a source of 

regulating reserves with the California ISO – are on the edge of commercial viability, and should 

not be written off as technological fantasy. BPA has investigated a number of these technologies 

as part of its Non-Wires pilot programs. In second phase of this project, the Northwest Power 

and Conservation Council intends to conduct a thorough review, including estimates of cost, 

application, and timetables for development, of the next generation of flexibility technologies. In 

the interim, the Technical Working Group has consulted with several of the nation’s leading 

experts on next generation of flexibility technologies and summarized them in the following 

matrix. 
Flexibility augmentation technologies 

Capital

Cost

(per kW 

basis) 

Operating 

Cost

Footprint 

(m2/kW) 

Life 

(yr)

Lead

Time 

State of

Technology 

Where 

Sited 

Locational

Constraint 

Scalable 

Storage Technologies Capacitors/ Ultracapacitors 

High Low Small 10-15 Long In

development

Load CS No 

Conventional Batteries 

Low Low Small 7 6 months Mature S-L CS Yes 

Flow BatteriesFlow/Redox [vanadium,zinc bromine, cerium zinc, polysulphide bromine, etc.] 

High Medium Small 10 - 15 medium Beta S-L CS Yes 

Other batterytechnology (e.g., lithiumion) 

High Low Small 7 No large

systems in place 

None in MWsize 

Load CS Yes 

Compressed Air [tanks,salt-domes] 

High Low

requiresnatural gas 

Tanks – Large Dome - small 

decades Medium Mature for

cavern 

Source???

Geologyyes, tanks no 

Geologyno, tankyes 

Flywheels Unknown Low Medium decades No MW

yet 

Alpha S-L CS Yes 

22 FR - Frequency regulation 

 LF - Within-hour load following DS - Diurnal to week-ahead storage  SS - Seasonal storage  SR - System reliability capacity 

D-3
Pumped 

storage hydro 

Moderate Very Low Large decades 10 yrs Mature Uniqu

e sites 

Geology No 

NAS Battery High Low Small 10 yrs 1 yr Early 

commercial 

S-L CS Yes 

Fuel Synthesis Storage Technologies Ethanol High Low Large decades 3 yr+ Early

commercial 

S-L Yes No 

Hydrogen High Very high Large decades 5 yrs+ Beta S-L No Yes Generation Technologies Simple-cycle GT /Recip Engine 

Low High Medium

to Large 

decades 3 yrs + Mature Source yes yes 

Duct firing(combinedcycle GT) 

Low Low Medium

to Large 

Decades Only at

construction 

Mature Source Yes No 

Fuel cells High Low Medium 5 -10 

yrs 

2 yrs Beta S-L,

fuel limited

CS Yes 

Add capacity to existinghydro projects 

High Low Small Decades 2-5 yrs Mature Source Yes Limited 

Call rights onstandby generation 

Low High Small N/A 1-3 yrs Mature Load yes yes 

Demand-side options Call rights onplug-in autofleet 

High Low N/A N/A Unknown Conceptual Load yes yes 

Loadinterruptibility rights 

Low High N/A Contract

life 

1 yr + Mature Load yes yes 

Dispatchable load cycling 

Low Low N/A 10+ yrs 1-3 yr + Mature Load yes yes 

Distributed Generation 

Moderate -High

High N/A Decades 1 yr + Early 

Commercial 

Load No Limited 

Operational techniques Stretching Can it be Low N/A N/A Years? Beta Source Yes No 

D-4
wind

prediction time

done?

Wind plantdispatchcontrol

? ? N/A N/A Contract 

based 

Mature, like loadinterrupt

Source Yes Yes 

D-5