Council Document 2010-09 A

p u b l i c a t i o

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f t h e 

# Sixth Northwest Conservation

and Electric Power Plan

February 2010

## Sixth Northwest Conservation and Electric Power Plan

Executive Summary Action Plan Chapter 1: Introduction Chapter 2: Key Assumptions Chapter 3: Electricity Demand Forecast Chapter 4: Conservation Supply Assumptions Chapter 5: Demand Response Chapter 6: Generating Resource s and Energy Storage Technologies Chapter 7: Transmission Chapter 8: Direct Use of Natural Gas Chapter 9: Developing a Resource Strategy Chapter 10: Reso urce Strategy Chapter 11: Climat e Change Issues Chapter 12: Capacity an d Flexibility Resources Chapter 13: Bonneville’s Obligations Chapter 14: Regional Adequacy Standards

Appendices
A. Fuel Price Forecast
B. Economic Forecast
C. Demand Forecast
D. Wholesale Electricity Price Forecast
E. Conservation Supply Curve Development
F. Model Conservation Standards
G. MCS Cost-Effectiveness for Residences
H. Demand Response
I. Generating Resources J. Regional Portfolio Model
K. Smart Grid
L. Climate Change and Power Planning
M. Integrating Fish & Wildli fe and Power Planning
N. Financial Assumptions and Discount Rate
O. Calculation of Revenue Requir ements and Customer Bills
P. Methodology for Determining Quantifiable Environmental Costs and BenefitsSixth Northwest Conservation and Electric Power Plan 

# Sixth Power Plan Overview

Summary........................................................................................................................ ................. 1 Future Regional Electricity Needs.............................................................................................. .... 2 Resource strategy.............................................................................................................. .............. 3 Efficiency..................................................................................................................... ............... 4
Generation Alternatives ........................................................................................................ ...... 5 Climate Change Policy .......................................................................................................... ......... 6 Capacity, Flexibility, an d Wind Integration ................................................................................... 7 Fish and Wildlife Program and the Power Plan.............................................................................. 8



## SUMMARY

The Pacific Northwest power system is faced wi th significant uncertainties about the direction and form of climate change policy, future fu el prices, salmon recovery actions, economic growth, and integrating rapidly growing amounts of variable wind generation. And yet the focus of the Council’s power plan is cl ear, especially with regard to the important near-term actions.

The Council’s power plan addresses the risks thes e uncertainties pose for th e region’s electricity
future and seeks an electrical res ource strategy that minimizes the expected cost of, and risks to, the regional power system over the next 20 years. Across multiple scenarios considered in the development of the plan, one conclusion was cons tant: the most cost-effective and least risky resource for the region is improved efficiency of electricity use.

In each of its power plans, the Council has f ound substantial amounts of conservation to be cheaper and more sustainable than most other types of generati on. In this Sixth Power Plan, because of the higher costs of alternative gene ration sources, rapidly developing technology, and heightened concerns about global climate change, conservation holds an even larger potential for the region.

The plan finds enough conservation to be availabl e and cost-effective to meet 85 percent of the region’s load growth for the next 20 years. If developed aggressive ly, this conservation, combined with the region’s past successful development of energy efficiency could constitute a resource comparable in size to the Northwest federal hydroelectric system. This efficiency resource will complement and protect the Northw est’s heritage of clean and affordable power.

Aggressive pursuit of this conservation is the pr imary focus of the power plan’s actions for the next five years. Combined with investment s in renewable generati on as required by state renewable portfolio standards, improved efficiency will help delay investments in more expensive and less clean forms of electricity until th e direction and form of future climate change legislation becomes clearer, and alternative low-carbon energy technologies become costeffective.

At the same time, the region cannot stand still in maintaining and improving the reliability of its power system. Investments to add transmissi on capability and improve operational agreements are important for the region, both to access grow ing site-based renewable energy and to better integrate it into the power system . The Council also expects that there are small-scale resourcesPlan Overview Sixth Power Plan

2 available at the local level in the form of cogeneration or rene wable energy opportunities. The plan encourages investment in thes e resources when cost-effective.

The power plan recognizes that meeting capacity needs and providing the flexibility reserves necessary to successfully integrate growing vari able generation sources may require near-term investments in generation resource s to provide reliable electricity supplies in specific utility balancing areas. In addition, individual utilities have varying degrees of access to electricity markets and varying resource needs. The Council’s regional power plan is not necessarily a plan for every individual utility in th e region, but is intended to provi de guidance to the region on the types of resources that shoul d be considered and their priority of development.

The near-term actions recommended in the Counci l’s Sixth Power Plan are important, but the region cannot neglect longer-term needs. Th e plan encourages research in advanced technologies for the long-term de velopment of the power system. For example, emerging smartgrid technologies could make it possible for c onsumers to help balan ce supply and demand. By providing information and tools to consumers to ad just electricity use in response to available supplies and costs, the capacity and flexibility of the power system would be enhanced. Smartgrid development also may facilita te the deployment of plug-in hybrid electric vehicles that work in concert with the power system to improve th e use of available gene rating capacity and help
reduce carbon emissions in the tr ansportation sector. In genera l, these technologies offer the potential to fundamentally change the power system while improving its efficiency and reliability. Developing these tec hnologies is a long-term process that will require many years to reach full potential, but the re gion can facilitate progress through research, development, and demonstration of the technologies.

Along with the smart grid, other technologies may be able to provide power when it is needed with low cost, low risk, and low emissions. In the future, the region may find greater value in power generated by geothermal resources, ocean waves, tides, gasified coal with carbon sequestration, advanced nuclear, or currently unknown technologies. New methods to store electric power, such as pumped storage or adva nced battery technologies may enhance the value of existing variable generation like wind. Given the uncertainties of the future, the region should not concentrate on any one potential future so lution to its power supply, but should explore a diversity of potential sources of fu ture energy generation and conservation.



## FUTURE REGIONAL ELECTRICITY NEEDS

The Pacific Northwest is expected to devel op and expand over the next 20 years. Regional population is likely to increase from 12.7 millio n in 2007 to 16.7 million by 2030. This four million increase compares to a 3.8 million increase between 1985 and 2007. The population growth will be focused on older age categories as the baby boom generation reaches retirement age. While the total regional population is pr ojected to increase by over 28 percent, the population over age 65 is expected to nearly double. Such a large shift in the age distribution of the population will change consumption patterns and electricity uses. Some possible effects could include increased health care, more retire ment and elder care facilities, more leisure activities and travel, and smaller-sized homes.

The cost of energy (natural gas, oil, electricity) is expected to be significantly higher than during the 1980s and 1990s. Although these prices have decreased significantly since the summer ofPlan Overview Sixth Power Plan

3 2008, a significant portion of the reductions are likely due to the effects of the current economic recession. Natural gas prices have also been affected by the recent growth of production from nonconventional natural gas supplies. The technology to retrieve these supplies cost-effectively has only developed recently and has improved expectations of adequate future supplies. Nevertheless, the cost of findi ng and producing these supplies is higher than for conventional supplies, which increases the estimated future price trend for natural gas.

If carbon emissions taxes or cap-a nd-trade policies are implemented, energy costs are likely to increase. Some of the planning scenarios used to develop this plan in clude a wide range of possible carbon mitigation costs from zero to $100 pe r ton. The expected average prices in this range start at zero a nd increase over time to $47 per ton of CO 2 emissions by 2030. Carbon costs can have a significant impact on electricity costs a nd prices to consumers. While higher prices reduce demand, they also stimulate new sources of supply and efficiency and make more efficiency measures cost-effective.

Electricity load (before account ing for new conservation) is expected to grow by about 7,000 average megawatts between 2009 and 2030, growing at about 335 average megawatts, or 1.4 percent, per year. Residential and commercial sector electricit y use account for much of the growth in demand. Contributing to the growth in the residential sect or is an anticipated increase in air conditioning and consumer electronics. Als o, summer peak electricity use is expected to grow more rapidly than annual energy. All of this growth in energy demand must be met by a combination of existing resources, more efficien t use of electricity, a nd new generation. An important change for the Sixth Powe r Plan is that electricity needs in the future can no longer be adequately addressed by evaluati ng only average annual energy requirements. In the future, resource needs must also consider capacity to meet peak load and the flexibility to provide within-hour, load-following, and regulation se rvices. The requirem ents for within-hour flexibility reserves have increased because of the growing amount of variable wind generation located in the region.



## RESOURCE STRATEGY

The Council’s resource strategy for the Sixth Po wer Plan provides guidance for the Bonneville Power Administration and the region’s utilities on choices that will help meet the region’s growing electricity needs while also reducing the risk associ ated with uncertain future conditions. The strategy minimizes the cost of , and risks to, the future power system. The timing of specific resource acquisitions is not th e essence of the strate gy because the timing of resource needs will vary for every utility. Rather, the important message of the resource strategy
lies in the nature of the res ources and their priorities.

The resource strategy can be summari zed in five specific recommendations:

1. Improved efficiency of electricity use is by far the lowest-cost and lowest-risk resource available to the region. Cost -effective efficiency should be developed aggressively and
on a consistent basis for the foreseeable futu re. The Council’s plan demonstrates that cost-effective efficiency improvements could on average meet 85 percent of the region’s growth in energy needs over the next 20 years.Plan Overview Sixth Power Plan

4 2. Renewable resource development is required by resource portfolio st andards in three of
the four Northwest states. The most read ily available and cost-effective renewable resource is wind power and it is being de veloped rapidly. Wi nd requires additional strategies to integrate its variable output into the power system and, in addition, it provides little capacity value fo r the region. The region needs to devote significant effort to expanding the supply of cost-effective re newable resources, many of which may be
small scale and local in nature.

3. Remaining needs for new energy and capacity should be based on natural gas-fired generation until more attractive technologies become available. The resource strategy does not include any additional co al-fired generation to serve th e region’s needs. Further, the Council’s plan demonstrates that mee ting the Northwest power system’s share of carbon reductions called for in some state, regional, and federal carbon-reduction goals will require reduced reliance on the region’s existing coal plants.

4. The challenges of wind integration and the need for additional within-hour reserves initially should be addressed through impr ovements in system operating procedures and business practices. Changes in wind forecas ting, reserve sharing among control areas, scheduling the system on a shorter time scal e, and advancing dynamic scheduling can all help address wind integration a nd contribute to a more effi cient use of existing system flexibility. The region is already maki ng significant progress in these areas.

5. Finally, the Council’s resource strategy calls for efforts to expand long-term resource alternatives. The region should demonstrate th e potential of smart-gr id applications to improve the operation and reliability of the regional power system and to access the potential of consumers to provide demand respon se for the capacity and flexibility of the power system. The region should continue to assess new efficiency opportunities, expand the availability of cost-effective renewable energy technologies, and monitor development of carbon capture and sequestration, advanced nuclear technologies, and
other low-carbon or no-carbon resources.



## Efficiency

The Council’s power plan includes a detailed anal ysis of efficiency pot ential in hundreds of applications. The achievable technical potential of efficiency improvements increased from the Fifth Power Plan levels due to advancing tec hnology, reduced cost, and estimates in new areas such as efficiency in electricity distribution sy stems, consumer electroni cs, and street, parking, and exterior building lighting. In addition, th e cost-effectiveness of these technologies has increased significantly because avoided costs have doubled and carbon-cost risk is several times higher than in the Fifth Power Plan. The estimat ed achievable potential conservation is nearly 6,000 average megawatts for measures cost ing under $100 per megawatt-hour. Over 4,000 average megawatts are available at a cost of less than $40 per megawatt-hour. These increased opportunities exclude future savings from efficien cies that have already been secured through building codes and appliance efficiency standards.

The plan shows that a substant ial amount of the growth in el ectricity demand could be met by conservation. Portfolio model analysis shows that over 5,900 average me gawatts of conservation are cost-effective, double the amount in the Council ’s Fifth Power Plan. The amount that can bePlan Overview Sixth Power Plan

5 achieved is constrained by the commercial avai lability of technologies, limits on the annual development rate, and an ultimate penetration rate limit of 85 percent. The amount of conservation found to be cost-effective changed ve ry little in response to changing assumptions about carbon costs and policies. Conservation in the plan is projected to be responsible for reducing carbon emissions by 17 million tons pe r year by 2030, a 30 percent reduction in 2030
emissions. Failure to achieve the conservation include d in the plan will incr ease both the cost of, and risks to, the power system and likely prevent Washington and Oregon from meeting legislated carbon-reduction goals.



## Generation Alternatives

The Council analyzed a large number of alterna tive generating technologie s. Each of these technologies is compared in terms of risk ch aracteristics and cost with other generating technologies, efficiency improvements, and demand response. In addition, resource
contributions need to be considered in te rms of their energy, cap acity, and flexibility
characteristics.

Generating technologies that ar e technologically mature, meet restrictions on new plant emissions, and are cost-effective are limited in the short to intermediate term. Wind remains the primary large-scale, cost-effective renewable ge neration source in the near term. However, the Council believes there likely are small-scale disper sed renewable generation alternatives that are local and site-specific. Cost -effective development of these is encouraged, even though the Council currently lacks enough information to include them explicitly in the plan. Natural gasfired generation is also feasible and cost-effectiv e. New coal-fired genera tion is difficult to site and permit, and prohibited in many states by new plant emissions standards. During the next 20 years, alternatives may develop such as carbon separation and sequestrati on, maturing renewable technologies, advanced nuclear generation, de mand response, smart-grid technologies, and storage strategies to help provide flexibility reserves. When CO 2 costs are added to the direct cost of generating alternatives, the cost of most generating res ource alternatives range between $70 and $105 per megawatt-hour or higher (levelized 2006$).

New renewable generation (primarily wind) is requi red to meet renewable portfolio standards in Washington, Oregon, and Montana. Analysis sh ows that meeting RPS requirements uses most of the 5,300 megawatts of readily accessible wind potential in the region. In addition to the wind, some geothermal resources were found to be attractive. However, the amount of geothermal potential is considered quite limite d. Given the risk that a carbon-pricing policy might be enacted in the future, some renewa ble generation is cost-e ffective even without renewable portfolio standards.

Natural gas-fired generation is anticipated toward the middle of the planning period. Natural gas is attractive for energy and capacity needs and provides an ability to displace coal plants in the event of high carbon costs or coal plant closures . Both combined-cycle turbines and simplecycle turbines are included in most scenarios. Although these na tural gas plants are sited and licensed in the plan, this does not occur until after the five-year action plan period. Preparing to add natural gas-fired generation he lps protect against th e risk of uncertain future conditions, but the generating plants are not actually completed in many of the simulated futures during the 20- year planning period. The Council recognizes th at individual utilities’ needs and access to market resources vary. Some utili ties will need additional resources in the near-term even if theyPlan Overview Sixth Power Plan

6 meet their renewable portfolio standards and acqui re all conservation ava ilable to their service
territories.

During the last 10 years of the power plan the ge nerating resource priorities become less clear. Given current climate change policies and conc erns, new coal without carbon sequestration is unlikely. Further, any significant reduction in carbon will require reduced operations of existing coal plants. Alternatives beyond greater reliance on natura l gas are typically unproven commercial technologies or alterna tives that require si gnificant new transmission investments. Long-term generating resources considered in clude wind developed outside the region and imported on new transmission lines, advanced nucl ear, gasified coal w ith carbon sequestration, and development of relatively unproven renewabl e resources, or ones th at are currently too expensive. Natural gas is used in the plan to meet long-term needs, but the Council recognizes that other alternatives are likely to become ava ilable over time. In par ticular, the evolution of smart-grid technologies could sign ificantly change the nature of future power system needs and
the kinds of resource alternat ives required and available.



## CLIMATE CHANGE POLICY

Addressing the topic of uncertain climate policies was identified as one of the most important
issues for the Sixth Power Plan. The focus of climate policy, especially for the power generation sector, will be on carbon dioxide emissions. Na tionwide, carbon dioxide accounts for 85 percent of greenhouse gas emissions. Nationally, abou t 38 percent of carbon dioxide emissions are emitted from electricity generation, but for the P acific Northwest the power generation share is only 23 percent because of the hydroelectric sy stem. Analysis by others has shown that substantial and inexpensive reductions in car bon emissions can come from more efficient buildings and vehicles. More expensive reduc tions can come from substituting non- or reducedcarbon electricity generation such as renewable resources, natural gas, and nuclear generation, or from sequestering carbon.

Reductions in carbon emissions can be encouraged through various policy approaches, including regulatory mandates (RPS or emi ssion standards), emissions cap-and-trade systems, emissions taxation, and efficiency improvement programs. State policy responses within the region to climate change concerns have focused on re newable energy standards and new generation emission limits. In addition, Oregon and Wash ington have carbon reduct ion targets adopted by statute. National and regiona l proposals have focused on cap-and-trade systems intended to reduce carbon and other greenhouse gases, although none have been implemented successfully in the region. Although carbon taxes are easier to implement than cap-and-trade systems, policy discussions have focused mainly on cap-and-trade systems.

The question for the power plan is what strate gies are prudent given a future where carbon pricing policies are unclear. The Council does not take a position on any particular regional carbon reduction goal or carbon pr ice in this power plan. The plan does recognize the uncertainty about future carbon pr ices and that possible carbon em ission reductions are important risk issues for the regional power system. Multiple carbon reduction scenarios, including a carbon risk scenario that considers a range of fu ture carbon prices between zero and $100 per ton provide relevant information for policy makers in the region. In general, the resource strategy in the plan will allow Washington and Oregon to meet their carbon reduction targets and constructively address the risk of uncertain future carbon policy. According to Council analysis,Plan Overview Sixth Power Plan

7 states and/or the federal government will need to take additional ac tions in order to achieve these targets. Potential carbon pricing plays an impor tant role in the Council’ s resource strategy, with the exception of the conservation resource, which remains a key component regardless of climate change policy assumptions.

The key findings from the Council’s analysis of climate change policies include the following:

• Without any carbon control policies, includi ng existing ones, carbon emissions from the Northwest power system would continue to grow to 6 percent ove r 2005 levels by 2030. However, without the significant amount of c onservation (which is cost-effective even without carbon policies) the growth in emissions would be far greater.

• Without additional carbon pricing policie s, current policies would stabilize carbon emissions from the Northwest power system at 2005 levels, but not meet current carbon reduction goals.

• Assuming a risk of higher carbon prices, the Si xth Power Plan resource strategy has the potential to reduce average re gional power system carbon em issions to 9 percent below 1990 levels, or 30 percent below 2005 levels, adjusted for normal hydro conditions.

• Significant reductions of carbon emissions from the Northwest’s power system require reduced reliance on coal, which currently em its more than 85 percent of the carbon dioxide from the regional power system. A carefully coordinated retirement and replacement of half the existing coal-fi red generation serving the region with conservation, renewable generation, and lowe r carbon-emission resources could reduce average carbon emissions to 18 percent below 1990 levels.

• To the extent that public policy raises the co st of carbon, we can expect an increase in a typical consumer’s electric bill and a decrea se in carbon emissions, especially when the carbon price begins to exceed $40 per ton. A fixed carbon price of $45 dollars per ton
has a similar effect on carbon emissions as retiring half of the existing coal-fired generation. Both would meet current carbon reduction targets for 2020 on average, but coal retirement would provide more certainty in meeting the targets.

• Preserving the capability of existing regiona l hydroelectric genera tion will help keep power system costs and carbon emissions down. In scenarios where the capability of existing resources are reduced, whether hydroele ctric or coal, the energy and capacity are largely replaced with gas-fired generation to maintain the adequacy and reliability of the power system.



## CAPACITY, FLEXIBILITY, AND WIND INTEGRATION

Reliable operation of a power system require s minute-to-minute matching of electricity generation to varying electricity demand. In the Pacific Northwest, resour ce planners have been able to focus mostly on annual average ener gy requirements, leaving the minute-to-minute balancing problem to system operators. This wa s because, historically, the hydroelectric system had sufficient peaking capacity a nd flexibility to provide the need ed operations as long as there was sufficient energy capability. This is changing for severa l reasons: growing regionalPlan Overview Sixth Power Plan

8 electricity needs are reducing the share of hydroelectricity in tota l demand, peak load has grown faster than annual energy, the capacity and flexib ility of the hydro system has been reduced over time for fish operations, and growing amounts of variable wind generation have added to the balancing requirements of the system.

As a result, planners must now consider potentia l resources in terms of their energy, capacity, and flexibility contributions. The rapid growth of wind generation (which has little capacity value and increases the need for flexibility rese rves) means that meeting growing peak load and flexibility reserves will require adding these capa bilities to the power syst em. Changes can be made to the operation of the power and transmissi on system that will reduce flexibility reserve needs. These operational change s are expected to cost less than adding peaking generation, demand response, or flexibility storage, a nd they can be implemented more quickly.



## FISH AND WILDLIFE PROGRAM AND THE POWER PLAN

The Columbia River Basin Fish and Wildlife Pr ogram is by statute incorporated into the Council’s power plan. The fish and wildlife prog ram guides Bonneville's efforts to mitigate the
adverse effects of the Columbia River hydroelectric system on fish and wildlife. One of the roles of the power plan is to help assure reliable implementation of fish and wildlife hydrosystem operations. The Columbia River power system operators have reliably provided hydrosystem actions specified to benefit fish and wildlife (and Bonneville ratepaye rs have absorbed the cost of those actions) while maintaining an adequate, e fficient, economic, and reliable energy supply. This is so even though the hydroel ectric operations for fish and w ildlife have a sizeable impact on power generation. On average, hydroelectri c generation is reduced by about 1,200 average megawatts, relative to operation without any cons traints for fish and wildlife. Since 1980, the power plan and the Bonneville Power Admini stration have addressed this impact through changes in secondary power sale s and purchases, by acquiring c onservation and some generating resources, by developing resource adequacy st andards, and by implementing other strategies to minimize power system emergencies and events th at might compromise fish operations.

In addition to operational changes, most of the di rect cost and capital co sts of fish and wildlife programs have been recovered through Bonneville re venues and Bonneville has absorbed the financial effects of lost genera tion, resulting in higher electricity prices. Bonneville estimates
that the total financial effect of replacing lost hydropower capab ility and funding direct fish and wildlife program expenditures totals from $750 milli on to $900 million per year (a range affected by, among other things, water cond itions and electric prices). The power system is less economical as a result of fish and wildlife pr ogram costs, but still economical in a broad affordability sense when compared to the costs of other reliable and available power supplies.

The future presents a host of uncertain changes th at are sure to pose challenges for the successful integration of power system and fish and wildli fe needs. These include possible new fish and wildlife requirements, increasing wind generation a nd other variable renewa ble integration needs that could require more flexibili ty in power system operations, c onflicts between climate change policies and fish and wildlife operations, possibl e changes to the water supply from climate change that might make it more difficult to deli ver flows for fish and meet power needs, and possible revisions to Columbia River Treaty operations to match 21st century power, flood control, and fish needs.Plan Overview Sixth Power Plan

9 To address current operations and prepare fo r these additional chal lenges, the Council has adopted a regional adequacy standa rd to help ensure that events like the 2000-01 energy crisis, in which fish operations and power costs were affect ed, do not happen again. In addition, the Wind Integration Forum is addressing issues with inte gration of wind into th e power system. Large swings in wind output have sometimes advers ely affected hydropower and fish operations. Addressing adequacy and flexibility issues in the Sixth Power Plan will improve electricity reliability and help ensure reliable fish operations.Sixth Northwest Conservation and Electric Power Plan 

# Sixth Power Plan Action Plan

Introduction................................................................................................................... .................. 1
Conservation ................................................................................................................... ................ 1 Deployment..................................................................................................................... ............ 2 Adaptive Management............................................................................................................ .... 5 Development and Confirmation.................................................................................................. 8 Generating Resources ........................................................................................................... .......... 9 Generating Resource Acquisition ............................................................................................. 10 Adequacy of System Integration Services ................................................................................ 11 Information to Support Sound Planning and Decisionmaking ................................................. 15
Future Role of Bonneville...................................................................................................... ....... 15 Ensuring Adequacy.............................................................................................................. ......... 18 Demand Response................................................................................................................ ......... 19
Smart Grid..................................................................................................................... ................ 20
Transmission................................................................................................................... .............. 21
Fish and Power................................................................................................................. ............. 22 Monitoring Plan Implementation................................................................................................. . 23 Maintaining and Enhancing Council ’s Analytical Capability ...................................................... 23



## INTRODUCTION

The action plan describes things that need to ha ppen in order to implement the Council’s Sixth Power Plan. It focuses on the next five year s and the priorities in the plan. Actions are organized by resource areas, Bonneville Power Administration, and Council monitoring activities. In many cases, the action plan suggest s the entities that have primary responsibility for implementation activities.



## CONSERVATION

Energy efficiency is the first priority resource in the Northw est Power Act. The Council’s analysis for the Sixth Power Plan strongly affirmed that energy ef ficiency improvements provide the most cost-effective and least risky response to the region’s growing electricity needs. Further, accelerated acquisition of cost-effective effi ciency reduces the contribution of the power system to greenhouse gas emissi ons. With greenhouse gas reducti on policies in flux, and many new sources of carbon-free electricity expensive or lacking capacity contributions to go with their energy, accelerated acquisition of cost-effec tive efficiency can buy time to develop policies and identify alterna tive sources of carbon-free generation.

The region is increasing its efforts to accomp lish conservation through integrated resource planning requirements, state and utility programs, and the Northwest Energy Efficiency Taskforce. Nevertheless, achieving the level of conservation identified in the Sixth Power Plan is a task that will require aggressive actions by the region. The action plan of the Sixth Power Plan contains a list of recommendations that wi ll help the region to meet the efficiency challenge.Action Plan Sixth Power Plan

AP-2 Key areas for enhanced implemen tation activity include: (1) enhanc ing the region’s ability to acquire the identified efficiency potential; (2) in creasing efforts to identify and verify new costeffective and feasible technologies; and (3) d eveloping regional mechanisms to keep efficiency policies up to date with changing informati on, track and verify achievements, and adaptively manage regional efficiency ac quisition strategies.



## Deployment

CONS-1. Achieve the level of conservation resource acquisition identified in the Sixth Power Plan’s conservation target and acco mplish the other actions necessary to accelerate conservation deployment. [Utilities, Energy Trust of Oregon, Utility Regulators, Bonneville Powe r Administration, Northwest Energy Efficiency Alliance (NEEA), and States] 1 The Council target for regional acquisition of conservation over the first five years of the plan is 1,200 average megawatts. Consequently, activities, resources and budgets should be geared to acquire 1,200 average megawatts of savings from 2010-2014 from utility program implementation, market transformation efforts, and codes and standards not included in the regi onal load forecast. However, the Council recognizes that there is a level of uncertain ty inherent in its assessment of regional conservation potential, the pace of antici pated economic recovery, power market conditions, carbon control requirements, technol ogy evolution, the succ ess or failure of acquisition mechanisms and strategies, progr ess on research and development, and the adoption of codes and standards. This means that the total amount of targeted
conservation available in the first five years is uncertain. For this reason, the Council developed a range of likely conserva tion savings over the first years of 1,100 to 1,400 average megawatts. The Council will monitor the actual conservation savings acquired by the region by conducting reviews of the region’s progress each year during the initial five-year pl anning horizon of the Sixth Power Plan. More specifically, CONS16, calls for a mid-term review of regional progress toward the regional conservation target. This will permit the Council to consid er adjustments to its regional conservation target for the remainder of the period cove red by the action plan. In addition, the midterm review will assess the impact of the region’s progress on the acquisition of other resource development actions.

CONS-2. Develop and implement an action plan for measures that are commercially viable but relatively new to programs or markets. [Bonneville, Utilities, Energy Trust of Oregon, and NEEA] The Sixth Power Plan identifies new or technologically improved efficiency measures that are cost-effective to pursue. The plan identified nearly 6,000 average megawatts of cost-effective conserva tion realistically achievable over 20 years. Of that, approximately 2,500 average megawatts will require new initiatives, programs, market transformation efforts or progress towa rd adoption in codes and standards. While in the near term these measures make up a bout one-quarter of the conservation targets, activities to develop these measures need to start now so the region is positioned to place
increased reliance on them in the future. Th e Council believes that regional collaboration on initiatives to develop and deploy these m easures would greatly enhance their chance of success. This activity will require concurre nt market research to determine the most effective ways to develop and deploy these new measures. Each of these measures is at a

1 Format note: The text in brackets following the bolded actions identifies the implementing entities.Action Plan Sixth Power Plan

AP-3 different stage of development and require s a different implementation strategy. All require efforts beyond what is now being done. An initial list of these measures includes distribution system efficiency, commercial out door lighting, reside ntial heat-pump water heaters, residential ductless heat pumps, TV , set-top boxes, desktop PCs, PC monitors and industrial system optimization.

CONS-3. Provide continued funding, in adequate amounts, for the Northwest Energy Efficiency Alliance’s (NEEA) to support its market transformation efforts. [Bonneville, Utilities, and Energy Trust of Oregon] NEEA’s regional market transformation activities have proved to be a gr eat value. Market transformation has been a key part of the development of many existi ng efficiency initiatives, and will need to be so for many of the new initiatives that the region must take up.

NEEA’s newly adopted strategic plan should be funded by regional util ities. In addition, the region should institute an ongoing process to identify needed market transformation
efforts that are not in the current NEEA bus iness plan but which may be necessary to reach regional conservation targets. The pr ocess should include a mechanism, such as subscription-based initiatives, to adjust funding allocations between regional and local programs as market dynamics change and new opportunities arise.

CONS-4. Develop long-term partnerships with energy efficiency businesses, trade allies and other parties in pro duct and service supply chains. [Bonneville, Utilities, Energy Trust of Oregon, NEEA, Governors, and States] Decisions to adopt efficiency measures and practices are made by consumers. Consumer’s decisions are influenced by many factors, including relations hips with the energy efficien cy industry and trade allies such as building designers, equipment vendors, contractors, engine ering firms, lighting designers, and the product and service options available to them. Accelerating consumer adoption of energy-efficient technologies a nd practices can be f acilitated by creating cooperative working relationships between NEEA and utility programs, product manufacturers, distributors, re tailers, and the energy efficien cy industry and trade allies to leverage their market relationships.

CONS-5. Support the adoption of cost-effective co des and standards and work to help ensure compliance. [Council, Utilities, Energy Tr ust of Oregon, NEEA, Bonneville, Governors and States] The Council will en courage the adoption of new codes in the region by working closely with the governors’ offices and with the responsible energy code adoption and enforcement agencies and othe r regional entities. This includes, but is not limited to the following activities:

• Advocating for the development and adop tion of cost-effective energy codes and equipment and appliance standards at the st ate and national level in a manner that is
consistent with the entities’ roles in the ac quisition of efficiency resources and legal limitations on political activities.

• Providing technical and political leadership in both legislativ e and rulemaking processes.

• Enhancing code compliance by working with local government officials to create a supportive environment and adequate f unding for comprehensive energy code implementation.Action Plan Sixth Power Plan

AP-4 • Providing technical and educational suppor t to code-enforcement staff.

• Developing and implementing a coordinated, high-level, adequately funded Pacific Northwest presence in federal efficiency sta ndard rulemaking processe s, to ensure that efficiency standards for federally regulate d appliances and equipment achieve costeffective energy savings.

CONS-6. Implement the Sixth Plan’s Model Conservation Standards (MCS). [utilities, Energy Trust of Oregon, NEEA, Bonneville , governors and states] This includes supporting the adoption of the MCS in state c odes and standards and working with local jurisdictions to increase compliance rates. It also includes im plementing programs to achieve savings from measures in the MCS not adopted into code and operating programs
consistent with the MCS for conservati on programs not covered by other MCS.

CONS-7. Adopt policies that encourage utilities to actively participate in the processes to establish and improve the implementation of state efficiency codes and federal efficiency standards in a manner that is consistent with their responsibility to acquire cost-effective efficiency resources. [utility regulatory commissions] For example, state regulators could clarify condi tions under which utilities could qualify for cost recovery for efforts to esta blish new codes and standards.

CONS-8. Support the ongoing operation of the Regional Technical Forum (RTF) and
assure that the RTF has suffi cient resources to review the new efficiency measures identified in the power plan. [Bonneville, utilities, Ener gy Trust of Oregon, and states] The financial resources provided to the RTF’ s to support its review of energy savings estimates, development of measurement and ve rification protocols, and establishment of measure specifications needs to be enhanced to cover the expanding suite of conservation
activities. In order to avoi d delaying the acceleration of regional conservation acquisition efforts the RTF will require increased funding to carry out its reviews in a timely and thorough manner. The region should provisiona lly increase its support of the RTF in
2010 at a level commensurate with estimated cost of identified research, analysis, tracking and evaluation while the Northw est Energy Efficiency Taskforce (NEET)
conducts a review of the RTF’s functi on, role, funding, and governance. Upon completion of the independent review, NEET should submit its recommendations regarding these issu es to the Council for consideration.

CONS-9. Develop energy savings verification protocols for conservation measures, practices, and programs when current verifi cation methods appear problematic or expensive or verification methods do not exist. [Regional Technical Forum] Streamlined measurement and verification prot ocols will allow the region to monitor the reality and persistence of savings as well as help Bonneville, the ut ilities, and regulators identify savings against targets and goals. The RTF should work with utilities for consistent guidance on tracking and verificati on of savings. Pursuant to CONS-17, the RTF should develop measurement and ve rification protocol s and/or recommend mechanisms for savings evaluation and verification that recognize the limited capabilities, customer and serv ice territory characteristics a nd experience of the region’s
small and/or rural utilities. The RTF shoul d prioritize its work to allow the region to move forward quickly to capture and verify savings. The RTF should also recommendAction Plan Sixth Power Plan

AP-5 improvements to the regional conservation m easurement and evaluation procedures based
on recommendations from the NEET workgroup as a starting point.

CONS-10. Develop a comprehensive library of es timates of savings from conservation measures and savings evaluation and measurement protocols. [Regional Technical Forum] Review and compare utility and En ergy Trust of Oregon savings estimates for measures not addressed by current RTF recommendations. Expand and update the library of energy savings estimates, over time resolve any inconsistencies, and make the library available for use across the region. Pursuant to CONS-17, in consultation with Bonneville and the region’s small and/or rura l utilities identify conservation measures that recognize the limited capabi lities, customer and service territory characteristics and experience of the region’s sm all and/or rural utilities.

CONS-11. In recognition of the higher goal for i ndustry-sector conservation, develop and implement a comprehensive strategy to improve the energy efficiency and economic competitiveness of industries in the region. [industry and trade allies, Bonneville, utilities, Energy Trus t of Oregon, NEEA, and states]

CONS-12. Consistent with standard practices fo r integrated resource plans, establish polices for incorporating a risk-miti gation premium for conservation in the
determination of the avoided cost used to establish the cost-effectiveness of
conservation measures. [state utility regulatory comm issions and utilities] The Council’s resource portfolio modeling identified valuable risk-mitigation benefits for the region from developing conservation. A ri sk-mitigation value should be incorporated
into conservation cost-effectiv eness methodologies used by u tilities and their regulators and system benefits administrators. The C ouncil recognizes that each utility and system benefits administrator is in a different pos ition with regard to the risks it faces. Regulators and utilities should establish policies on how to in corporate the estimated cost of addressing greenhouse gas emissions from thermal resources in conservation avoidedcost methodologies and inte grated resource plans.

CONS-13. Identify regulatory barriers and di sincentives to the deployment of conservation, and consider policies to address these barriers. [state utility regulatory commissions, investor-owned and publicly-o wned utilities, states, BPA and others] Responsible organizations should identify barrie rs to achieving efficiency improvements. Some policies to reduce ba rriers will be addressed th rough the Northwest Energy Efficiency Taskforce. Others may be addre ssed by individual util ities. The Council will work with regional interests to evaluate the use of prices and incentives to encourage the achievement of conservation targets. If so me utilities are having difficulty achieving the efficiency targets in the plan, they should c onsider pricing structur es, including the use of inverted block rates, to provide better in centives to their customers to improve the efficiency of their homes and businesses.



## Adaptive Management

The Council is well positioned to conduct pe riodic reviews of the remaining conservation potential, and of existing and planned conservatio n initiatives as well as conservation research and evaluation efforts. However, Bonneville, the utilities, the Ener gy Trust of Oregon, andAction Plan Sixth Power Plan

AP-6 NEEA, along with the states are best positioned to develop and adaptively manage the actual acquisition of conservation resources. These en tities have a long and successful history of developing strategies and fundi ng programs to acquire conservation, transform markets, and upgrade codes and standards.

CONS-14. Prepare a strategic and tactical plan to achieve the Sixth Power Plan’s regional conservation target and accomplish the other actions that are necessary to build the capability to accelerate conservat ion deployment for the remainder of the planning period in a cost-efficient manner. [Bonneville, utilities, Energy Trust of Oregon, and NEEA] A regional conservation implementation plan is needed to assure resources are being effectively deployed to reach the Sixth Power Plan’s conservation target. The Council recognizes that Bonnev ille, utilities, Energy Trust of Oregon, and NEEA are best positioned to prepare and adap tively manage the implementation of such a plan. However, the development and implem entation of this plan will require the active
collaboration of these entities with other market actors, including energy-efficiency
business and their trade allies , state and local governments, as well as associations and organizations that represent key customer groups. The Council belie ves that the plan should include specific actions focused on de veloping energy-efficiency technologies and practices. The plan should describe how thes e technologies and practices will be brought to market from conception to full deploymen t using local utility programs, coordinated regional programs, market transformation, co des and standards adop tion and enforcement and any other mechanism deemed appropriate and all parties should collaborate on the disaggregation of these savings into these delivery categories. In particular, the plan
should address the need to tr ansition from reliance on comp act fluorescent light bulbs (CFLs) to a more diversified portfolio of measures. Savings achieved through all of these
mechanisms

, including savings for utility-acquired CFLs until federal standards take effect in 2012, will count toward achievement of the Council’s conservation target. The plan should also set forth the level of funding for staffing and infrastructure needed for its successful implementation. Finally, the plan should develop quantifiable milestones to measure progress toward these targets and actions that can be evaluate d at strategic points over the five-year action plan. Progress toward these milestones should be reviewed in the mid-term report on progress toward meeting plan objectives (CONS-16).

CONS-15. Develop an ongoing mechanism to iden tify high-priority actions that will enhance the deployment of cost-effectiv e energy efficiency across the region. [Bonneville, Utilities, Energy Trust of Or egon, NEEA, State Regul atory Commissions, along with the States and the Council] Adap tive management of the implementation of the regional conservation action plan called fo r in CONS-14 will require timely decisions regarding the allocati on of resources between local, regional programs and market transformation initiatives; the continuation a nd expansion of successful existing programs and efforts; the modification or terminati on of poorly performing programs, and the development of new initiatives for new efficien cy measures and practices identified in the Sixth Power Plan. In order to accomplish this, the Council believes that a high-level forum for ongoing policy-level guidance on thes e issues should be formed. The Council
views this as a continuan ce of the NEET efforts to address the dynamic nature of conservation acquisition and, like NEET, th is forum must include senior-level management and decisionmakers to assure common understanding, commitments, and follow-through. While pursuant to the NEET recommendations NEEA has agreed to hostAction Plan Sixth Power Plan

AP-7 and facilitate regional effort s to better coordinate programs that do not adequately address
this need.

CONS-16. Report on progress toward meeting plan objectives. [Bonneville, utilities, Energy Trust of Oregon, and NEEA] As part of the Council’s biennial review of the Sixth Power Plan, Bonneville, Utilities, Energy Trust of Oregon, and NEEA should report on progress toward meeting the plan’s conservation targets and objectives. The report should include an assessment of progre ss toward mid-term milestones established in the strategic plan developed in CONS- 14. The Council recognizes that the plan’s conservation targets are based on an “expect ed value” across a wide range of potential futures. The actual future the region experi ences will differ in some regard from the plan’s assumptions. Therefor e, this report should iden tify whether the regional conservation acquisition plan (CONS-14), the implementation of that plan (CONS-15) and/or the Council’s target (CONS-1), need to be modified to account for conditions or circumstances different than expected. Thes e include slower- or fa ster-than-anticipated economic recovery, substantially different power market conditions, carbon control requirements, technology evolution, the succe ss or failure of acquisition mechanisms and strategies, progress on research and deve lopment and the adoption of codes and
standards.

CONS-17. Take into account the unique circumst ances and special barriers faced by
small and/or rural utilities in achiev ing conservation and the development and implementation of conservation programs. [Bonneville] Work with and give
assistance to these customers to ensure that their capabilities, customer and service territory characteristics, and experiences are addressed in the identification of conservation measures applicable in their service territories and in the implementation of
these conservation measures. Work with the RTF to see that these measures are expeditiously evaluated so that they are ava ilable to meet the conservation goals of small
and/or rural utilities. Assist these utilities as needed in their efforts to implement these conservation measures and help Bonneville m eet its share of the regional conservation target, working with these utilities either in dividually or pooled, as appropriate in each circumstance. Finally, a panel consisting of Bonneville and small a nd/or rural utilities should report its findings b ack to the Council during the mi d-term check-in of the Sixth
Power Plan.

CONS-18. In consultation with Bonneville, utilitie s, Energy Trust of Oregon, and NEEA develop recommendations on measure bundling, the use of cost-effectiveness tests, research and development investments, and other issues. [Council] Guidance is
needed to ensure that the Sixth Power Pl an’s conservation resource assessment is translated into acquisition programs and re search and development activities. The NEET process identified the Council as the lead for the developm ent of a cost-effectiveness reference document and the need for an ongoing process to assist uti lities and others in their efforts to design, implement, and administ er an effective and efficient conservation program using the data from the Council’s plan.

CONS-19. Develop and implement improvements to the regional conservation planning, tracking and reporting (PTR) systems so that energy efficiency savings and expenditures are more consistently and comprehensively reported. [Regional Technical Forum, utilities, Energy Trust of Oregon, Bonneville, NEEA, and states]Action Plan Sixth Power Plan

AP-8 Also identify a governance structure to guide improvement of the systems and funding agreements to share the responsibility for its ongoing operation and maintenance equitably. The tracking system should evolve over time so that conservation from all mechanisms and funding sources, including utility, state and local conservation programs, codes and standards, state and fede ral tax credits, mark et transformation, and non-programmatic changes in markets can be reported. Savings from market changes outside of programs may need to be tracked outside of the PTR system.



## Development and Confirmation

The Sixth Power Plan’s assessment of technicall y achievable energy efficiency resources relies on research and demonstration progr am results initiated as long a go as the early 1980’s. In order to expand the conservation options available in the future, and to confirm the resource cost, savings, and consumer acceptance of some measures identified in the plan, the region should
fund conservation research and demonstration ac tivities. The responsib ility for carrying out these activities varies with their purpose and sc ope. However, given the “community property” nature of the results of these projects, Bonnev ille, the utilities, NEEA and the Energy Trust of Oregon should, to the extent practicable, collaborate on funding and coordinate on implementation. At the same time, regulatory commissions should establis h guidelines to allow cost recovery for such research and demonstration activities.

CONS-20. In order to ensure the long-term s upply of conservation resources, develop and fund a regional research plan that directs development, demonstration, and pilot program activity. [utilities, Bonneville, Energy Trust of Oregon, NEEA and other program operators] The plan should focu s on both the new measures and practices
identified in the Sixth Power Plan conserva tion assessment and promising measures that emerge over the next five years that requi re additional technical, market, or other
research. An initial list of measures that shou ld be incorporated into the research plan is in an attachment to Appendix E. Assess feas ibility, collect and eval uate data on costs and savings (including load-shape impacts), and identify programmatic approaches, delivery mechanisms, implementation strategies, and in frastructure needs. The research plan
should :

a. Prioritize research needs based on the magn itude of potential savings and level of uncertainty of measure performance.
b. Identify research objectives that defi ne specific milestones or the knowledge sought in order to increase certainty and solidify resource com ponents of the longterm conservation supply.

c. Identify funding requirements and commitments to accomplish research objectives.
d. Assign the roles and responsibilities of th e various regional entities, including but not limited to the Regional Technical Fo rum, Bonneville, NEEA, utilities, Energy Trust of Oregon, and the states.

e. Identify milestones for reviewing res earch progress, determining additional research needs, and determining how regional conservation potential and associated targets should be adjusted ba sed on the findings. Periodic review of the research plan and findi ngs could be done as part of a biennium review of the power plan, or as needed.Action Plan Sixth Power Plan

AP-9 CONS-21. Develop a regional approach to support data needs for energy efficiency. [Bonneville, NEEA, utilities, Council and Region al Technical Forum] The region should develop a multi-year data coll ection and research plan that prioritizes the initiatives needed to facilitate the implementation of conservation resources and determine their impact on the power system. The plan should set forth a process to improve datacoordination, distillation, and dissemination and outline the most appropriate and costefficient way to acquire needed data. The de velopment of this plan should be carried out
in a manner consistent with the NEET recommen dations. Elements of this data collection work can assigned to the Regional Technical Forum, NEEA, Bonneville , and the utilities. High priority data needs include:

a. Residential and commercial building characteristics
b. Customer end-use surveys

c. Measured end use & savings load shapes
d. Efficiency measure saturations

e. Capacity impact of efficiency measures
f. Appliance and equipment saturations

g. Market/Supply Chain structure
h. Tracking of non-programmatic conservation savings

CONS-22. Establish guidelines to consider bala ncing utility and consumer interests, cost recovery for conservation research , demonstration, confirmation, and
coordination activities. [state utility regulatory commi ssions, public utility boards and commissions, and utilities]



## GENERATING RESOURCES

From a regional perspective, actions to develop new generating capacity in excess of that needed to meet state renewable portfolio standards is unlike ly to be needed within the next five years for purposes of energy adequacy, risk reduction or cost reduction. Individual ut ilities, however, may need to acquire energy generation capacity becau se of transmission or other limitations that constrain access to energy markets and surplus gene ration, or because of a need to reduce market price, fuel price or carbon exposure. The ac tion plan includes guideline s for energy acquisitions
in these circumstances.

Though the summertime surplus of firm capacity is declining, actions to develop additional firm capacity are not needed on a region al basis over the next five year s to maintain adequate winter or summer peaking reserves. As with energy, in dividual utilities may require additional firm capacity to maintain adequate reliability reserves.

Continued development of wind power to meet regional renewable portfo lio standards and for export 2 will continue to increase the demand for flexibility reserves. 3 This action plan includes actions to reduce the demand for system flexibility and to more fully access the latent flexibility

2 Bonneville and other balancing authorities are obligated to provide interconnection and integration services for generators irrespective of local need.

3 Flexibility reserves (also called bala ncing reserves, rapid-response reserves, or regulation and load-following capability) provide the ability to balance generation and load on a sub-hourly basis. Balancing within intervals of seconds to minutes is referred to as regulation. Balanc ing within the hour is referred to as load following.Action Plan Sixth Power Plan

AP-10 of the existing system. These actions are hi gh priority and are consistent with the recommendations of the Northwest Wind Integration Forum.

Even with implementing measures to enhance existing system flexibility, growing wind and other variable-output resources may require au gmenting flexibility reserves. Though the timing of this need on a regional ba sis is not well understood, Bonnevill e has asserted this may happen within several years because of the geographic concentration of wind development within its balancing area. The action plan includes actions to develop and implement a system to monitor the regional flexibility adequacy and guideline s for acquisition of balancing reserves.

Utilities that need to acquire new low-carbon em itting resources should consider the economic and environmental costs of the balancing reserv es to firm and shape this variable-output generation, as well as the economic and environm ental costs of the tran smission facilities to integrate such resources.

The action plan includes actions to improve the co st-effectiveness and commercial availability of emerging low-carbon generating resources and storag e alternatives with a focus on options of special relevance to the Northwest. Prosp ects include enhanced geothermal, wave energy, offshore wind, advanced and modular nuclear plants, solar photovoltaics, imported wind, concentrating solar power, tidal current energy, and technologies to capture, store or recycle carbon from existing and new fossil-fueled power pl ants. Technologies such as pumped storage, compressed air storage, batteries, and “smart gr id” technologies offer low-carbon approaches to augment system flexibility.

Sound power system planning requir es capable analysis tools a nd reliable supporting data. In particular, techniques and data to assess the mo st cost-effective approaches to develop and integrate variable-output resources long term ar e inadequate or lacking. This action plan contains actions to support im proved planning and decisionmaking.



## Generating Resource Acquisition

GEN-1. Acquisitions to meet energy, capacity, and ancillary service needs. Bonneville, other balancing authorities, and utilities needing to acquire resources to provide energy, capacity or anci llary services should seek to acquire the most costeffective, suitably reliable resources availa ble to provide the n eeded service. All potentially cost-effective altern atives capable of providing th e needed services should be considered including, but not limited to, conservation, demand management, storage, transmission, generating resources, operati onal and institutional solutions, and other emerging technologies (for example smart gr id technologies). Resource acquisition decisions should recognize the full value of services (e.g. energy, capacity, ancillary services, avoided transmission and distributi on costs, cogeneration load) provided by the available alternatives (e.g.,, and the full cost of services needed to support the available alternatives (e.g., costs of transmission, ba lancing services, and supplemental firm capacity). Significant investment, performance, environmental, and other risks should be quantified where feasible.

GEN-2. Facilitate development of smaller-scale, cost-effective, low-carbon resources. Generating resource development in recent years has been dominated by wind power andAction Plan Sixth Power Plan

AP-11 natural gas combined-cycle plants. Ho wever, smaller-scale renewable and highefficiency projects can be equally, if not more, cost-effective than these more prevalent
resources. Smaller-scale resource devel opment opportunities include waste heat energy recovery, bioresidue ener gy recovery, cogeneration, geothermal, hydropower upgrades and new hydropower projects. These opportuniti es are available in limited quantity and can be challenging to develop because of the complexity of business and fuel supply arrangements; costly or unique engineeri ng, interconnection and other infrastructure requirements; and proportionally high transact ion costs and long lead times. Design and engineering is often highly si te-specific, as are costs and business arrangements. If successful, however, these projects can provi de firm capacity, base load energy, avoided transmission and distribution costs, residue disposal solutions, lo cal economic benefits, low-carbon energy production, and reve nues to host facilities.

The Council encourages Bonnev ille and the utilities to facilitate development of these resources where cost-effective by activities such as the following:

• Surveying resource development potential

• Structuring requests for pr oposals to accommodate small and diverse projects

• Establishing “open windows” for unsolicited proposals

• Establishing standard power purch ase offers for qualifying projects

• Establishing standard interconnection provisions

• Considering all project attri butes in proposal evaluations

• Providing financial, engineering a nd other development assistance

• Supporting demonstration and pilot pr ojects for developing, testing and demonstrating technologies and business practices with poten tially widespread application



## Adequacy of System Integration Services

GEN-3. Reduce demand for system flexibility. The demand for balancing reserves forintegrating variable-output resources can be reduced by improved wind forecasting, subhourly scheduling, liquid intra-hour wholesale power markets, curtailment of wind plant output during severe ramp-up events, curtailm ent of wind export schedules during severe ramp-down events, and ACE 4 diversity sharing among balanc ing areas. Bonneville and other balancing authorities and grid entities s hould assess the feasibil ity, cost and benefits
of these and other measures to reduce the demand for balancing reserves and implement promising measures.

GEN-4. Expand access to existing system flexibility. The balancing capability of the existing power system is not fully availabl e because of business practices, operating protocols, transmission and communication limitations, abse nce of equipment allowing plants to be operated for bala ncing purposes, and environmenta l constraints. This latent balancing capability can be more fu lly tapped by expanded dynamic scheduling capability within the region and between in terconnected regions, and by retrofit of existing plants where feasible and if nece ssary to provide balancing capability. Bonneville, other balancing authorities, grid en tities, and plant owners should assess the

4 Area Control Error - A measure of the instantaneous di fference in scheduled and actual system frequency and a balancing authority’s scheduled and actual interchanges with other balancing areas.Action Plan Sixth Power Plan

AP-12 feasibility, cost, and benefits of expande d dynamic scheduling within region and across
the Northern and Southern interties. A ttractive opportunities fo r expansion should be developed.

GEN-5. Assess adequacy of system flexibility. Periodic assessments of the adequacy of available balancing capability for following load and for variable-output generating resource integration are needed to comple ment to existing assessments of energy and capacity adequacy. The Wind Integration Forum, working with the Resource Adequacy Forum should develop a metric and methodol ogy for evaluating the balancing reserve adequacy. Regular assessments of the ad equacy of balancing capability should be implemented once the metric and methodol ogy have been developed and tested.

GEN-6. Evaluate flexibility augmentation options. This plan recommends developing
wind and other renewable resources to offset carbon and natural gas price risks. Adding wind and other variable-output resources will continue to expand the need for balancing capability. In response, priority should be given to measures to reduce the demand for balancing reserves and measures to expand acce ss to the latent flexibility of the existing system, as called for in GEN-3 and GEN-4. However, Bonneville and other balancing authorities may eventually need to augment the supply of balancing capability to serve the expanding inventory of variable-output resources. The Council, working with the Wind Integration Forum and others, will asse ss the availability, reliability, and costeffectiveness of resources for augmenting th e existing balancing cap ability of the power system. Priority in this effort will be given to resources or combinations of resources that can jointly satisfy peak-load and system-flexi bility requirements. This effort will consider, but not be limited to, combined-c ycle plants, gas turbine generators and reciprocating engines, compressed-air ener gy storage, pumped-storage hydro, battery storage, smart grid technologies, and demand- side options. Metrics should be developed to measure and compare the various options. The completed assessment should identify research, development, and demonstration activ ities to ensure that the most promising options are available when required.

GEN-7. Commercialize and confirm low-carbon resources with special Northwest promise. Wave energy, deep-water wind power, enhanced geothermal power generation and salinity gradient energy systems have promise for future development in the Northwest as potentially abundant, low-carbon re sources. Yet these resources, together with tidal current generation, are technically immature a nd the benefits, costs, and consequences of commercial-scale devel opment insufficiently understood. Bonneville, regional utilities, industry gr oups, and the states, working with the federal government, should initiate and support effo rts to develop and demonstrate the relevant technologies. They should also work to establish th e body of knowledge and legal framework to support commercial development of the resources when available and needed. These efforts should include: 1) measuring the re source using a sufficient geographic scope, frequency, and duration to assess the economic s of the resource, identifying promising resource areas and assessing resource inte gration needs; 2) technology assessment; 3) identifying and resolving potential envir onmental, economic, and other development conflicts; 4) demonstration projects to test and evaluate technology; 5) assessing system integration needs; and, 6) pilot projects to se rve as the basis for commercial development.Action Plan Sixth Power Plan

AP-13 The Oregon Wave Energy Trust initiativ e is a comprehensive model resourceconfirmation effort.

GEN-8. Carbon separation and sequestration technologies. Though not yet fully commercial, carbon separation, sequestration, and recycling may prove to be an economic approach to reducing carbon dioxide releases in the l ong term. The Council encourages states and utilitie s to support efforts to develop commercial technologies for separation, sequestration, and recycling of carbon dioxide with emphasis on technologies unique to Northwest situations such as flood basalt sequestration. The Council also encourages the states to establish the legal framework for permitting and operating carbon dioxide transportation a nd sequestration facilities.

GEN-9. Monitoring development of other pr omising resources and technologies. Commercial development of other promisi ng technologies is likel y to be promoted primarily by policies, incentiv es, and other drivers at the fe deral level, or within other countries or regions where th e technology might play a particularly vital role. These technologies include post-combustion carbon di oxide capture from conventional fossilfuel power plants, algae-derived biofuel production and other carbon dioxide “recycling” technologies, integrated coal gasification combined-cycle technology, advanced nuclear technology, carbon dioxide sequestra tion in saline reservoirs and depleted gas and oil fields, and concentrating solar thermal a nd photovoltaic technol ogies. While active participation of the Northwest utility indus try in developing thes e technologies may not be needed, their development should be clos ely monitored, and join t participation in demonstration projects and other resource deve lopment efforts should be considered. In addition, the Council expects that the st rong energy research and development organizations present in the Northwest will pa rticipate in developing these technologies.

GEN-10. Resource development mandates and incentives. A diverse collection of federal and state resource development manda tes and incentives has developed over time. Their underlying public goals include commercializing immature, but promising, technologies, developing the power system and social infrastructure to support commercial-scale development of promisi ng resources, economic development, and promoting development of low-carbon resour ces. While these mandates and incentives are effectively promoting development of sp ecific resources, their focus on resource types rather than ends (e.g., GHG reduction, cost and risk minimi zation) may constrain development of equally attractive resources and affect efficient system operation. The Council, working with other in terested entities w ill review the impact and effectiveness of mandates and incentives, including consideration of the following:

a. Impact on optimal resource dispatch. The federal production tax credit and renewable energy credits lo wer the effective variable cost of generation, under some conditions to negative levels. C oncerns have been voiced that this can result in inefficient resource dispatch, a nd in some cases, increased environmental impact.

b. Effects of an unbundled REC market. Renewable energy credits (RECs) represent the environmental and renewa ble attributes of renewable energy production as a separate commodity from the associated energy. RECs can beAction Plan Sixth Power Plan

AP-14 transacted as “fully bundled” (delivered with the associated energy), “partly bundled” (the associated energy can be de livered within a specified time), or “fully unbundled” (marketed separately from the associated energy). As states, particularly California, move toward mo re aggressive and challenging renewable portfolio standards, interest in meeting RPS requirements with partially or fully
unbundled RECs has increased. Unbundli ng can expand the pool of qualifying resources available to utilities, and expa nd the customer base for developers of qualifying resources. Market flexibility and liquidity, less constrained by transmission considerations, should increas e. Because the value of CO2 reduction is not location-specific, greenhouse gas re duction benefits are preserved. Partly unbundled transactions will improve transm ission load factors and the need for new long-distance transmission lines will be reduced. Local economic benefits
will shift to areas rich in lower-cost qualifying resources. Unbundling, however,
raises issues of concern to resource-r ich areas such as the Northwest. The demand for, and cost of, balancing reserv es in the supply region will increase. The need for equitable allocation and recove ry of the cost of balancing services will become more acute. The residual (“null”) energy must be marketed within the supply region and may depress po wer prices and introduce additional volatility to the wholesal e power market. Dispatch conflicts with minimum hydropower operating limits a nd must-run resources may increase. Finally, the cost of acquiring RPS-qualifying and othe r low-carbon resources may rise for
Northwest utilities because of increased competition. The potential extent of the
future unbundled REC market should be asse ssed, the resulting benefits and costs
characterized and actions needed to remedy significant impacts identified.

c. Geothermal development risk reduction. Geothermal is an attractive, competitive low-carbon resource. Geot hermal development, however, is hampered by a financially risky resour ce exploration and confirmation phase.
Current federal incentives that reward successful production may be insufficient
to offset the investment risk of resource development. Earlier federal incentives intended to offset resource explorati on and development risk resulted in substantial geothermal power develo pment and production. The cost and effectiveness of a range of incentives shoul d be assessed to determine what set of incentives appear to be the most co st-effective in stimulating productive geothermal development.

d. Promote CO 2 reduction parity of resource mandates and incentives. The principal underlying public purpose of many resource mandates and incentives is to reduce greenhouse gases, yet CO 2 reduction potential is not always reflected in
the structure and level of mandates and in centives. An example is the prevalent failure to equate the carb on dioxide reduction potential of energy efficiency with that of renewable generating resources in state renewable portfolio standards. This may result in overly costly carbon dioxide reduc tion and a greater environmental impact by diverting expe nditures from conservation to renewable resource development. States should atte mpt to establish a reasonable parity in the treatment of resources, including ener gy efficiency, in the design of renewable portfolio standards and other low-carbon resource incentives.Action Plan Sixth Power Plan

AP-15 

## Information to Support Sound Planning and Decisionmaking

GEN-11. Resource Assessment. Bonneville, working with th e Council, should re-establish a program of periodically assessing the availa bility, cost, and perf ormance of generating
resources and associated technologies to support the Council’s power plan and Bonneville’s resource program. These assessments should focus on resources identified in this plan with near- or longer-term pr omise to the Northwest, including waste-heat energy recovery, bioresidue energy recovery, cogeneration, conventional and enhanced geothermal, hydropower upgrades, new hydropower projects, natural gas technologies for energy, firm capacity and flexibility, wave, and offshore wind power. This work should
be coordinated with the inventories of sm all-scale renewable en ergy and cogeneration
resources called for in GEN-2.

GEN-12. Planning for optimal development of the power system. The Council will work with the Wind Integration Forum and other in terested entities to identify the optimal development of a future power system cont aining a high penetration of wind and other
new low-carbon resources. This effort should assess the cost and environmental tradeoffs
associated with various combinations of tr ansmission facilities, ba lancing capacity, and storage capacity needed to secure remote or local low-carbon resources. The work will consider the diversity value, and possibly greater productivity, of wind developed on a broader geographic basis, and the tradeoff be tween conditional firm transmission service and the value of delivered wind energy. So lar, wave, tidal current, and offshore wind sources of low-carbon power should also be evaluated. This work will draw on the results of the flexibility augmentation asse ssment to estimate the availability, cost, and performance of new sources of system flex ibility, including various generating, demandside, and storage options.

GEN-13. Long-term synthetic, hourly wind data series. The Resource Adequacy Forum should complete a long-term synthetic, hourly wi nd data series. This work is needed to further refine estimates of the sustained peak ing value of wind, and to implement analytic capability to evaluate the tradeoffs betw een hydropower operational constraints and providing flexibility from the hydropower system.



## FUTURE ROLE OF BONNEVILLE

The Bonneville section of the action plan en courages Bonneville and its customers to successfully complete and implement the regional dialogue policy and contra cts. It recognizes that there remains litigation on so me of the elements of the policy, and encourages Bonneville and its customers to resolve the issues, or if necessary, to seek a legislative solution to the contested areas. The action plan says Bonnev ille should follow the Counc il’s regional resource strategy in its own acquisitions, and meet its share of the conservation targets as it has agreed to do. Bonneville should actively fund and support re gional conservation acti vities and provide incentives and support for utility conservation acquisi tions. It specifies th at Bonneville continue to meet its fish and wildlife mitigation responsibilities.

BPA-1. Implement the Council’s Plan. Pursuant to the overall directives of the Act, Bonneville's resource acquisition activities s hould be consistent with the Council's powerAction Plan Sixth Power Plan

AP-16 plan, including the resource strategies relevant to Bonneville identified in other sections of the action plan and further described in Chapter 12.

BPA-2. Conservation goals. Bonneville should meet its conservation goals. The
Council believes Bonneville should observe cert ain principles in de signing its post-2011 energy efficiency efforts. These principles include:

a. Conservation targets. Bonneville should continue to commit that it will work with its public utility customers and m eet Bonneville’s shar e of the Council’s conservation targets. Bonneville should ensure that public utilities have the incentives, support, and flexibility to pursue sustained conservation acquisitions appropriate to their service areas in a coope rative manner, as set forth in detail in the conservation action plan items, especi ally in the introduction and in CONS-1,
CONS-14 and CONS-17. The Council s upports Bonneville’s regional dialogue policy to fund conservation pr imarily as a tier 1 obligation of the federal base system (FBS).

b. Utility reporting. Bonneville should enforce pr ovisions in its power sales contracts that require utility reporting and verification of conservation savings so
that Bonneville and the C ouncil can track whether cons ervation targets are being
achieved.

c. Implementation mechanism. Bonneville should offer flexible and workable programs to assist utilities in meeting the conservation goals, including a backstop role for Bonneville should utility pr ograms fail to achieve these goals.

d. Regional conservation support. Bonneville should continue to be active in funding and implementing conservation programs and activities that are inherently regional in scope, such as the Northwest Energy Efficiency Alliance, the Regional Technical Forum, and other regional efforts proposed as a result of the Northwest Energy Efficiency Taskforce process.

BPA-3. Additional resources, including capa city and flexibility priorities. Bonneville may have a need for additional resources for a number of reasons, including possible resource acquisitions to addre ss capacity and flexibility needs, after taking account of its conservation acquisition. Bonneville should make these resource acquisition decisions consistent with the following:

a. Institutional changes to meet flexibility needs. Bonneville should aggressively pursue the various institutional and busin ess practice changes that are currently being discussed to reduce the demand for flexibility, and more fully to use existing resources (federal and non-federa l) for its balancing needs, before acquiring additional generating resources for this purpose. These institutional measures, including better forecasting, s hort-term wind curtailment, sub-hourly scheduling, markets for the exchange of balancing services among balancing authorities, generation owners and oper ators, and demand response providers, have the potential to be more cost-effec tive and faster to develop than building new generation.Action Plan Sixth Power Plan

AP-17 b. Generation for capacity and flexibility. Institutional changes described above may require complex multilateral agreemen ts and similarly complex changes in operating systems. And even if accomplished, these changes may not completely
solve Bonneville’s fl exibility needs. Given thes e factors, BPA may need to acquire flexibility or capacity resources that could include investments in a smart grid and storage. Bonneville should take a broad look at the cost-effectiveness and reliability of the possible sources of additional capacity and flexibility if it turns out they are needed to meet its obligations. The possible synergies in simultaneously meeting both capacity and flexibility requirements need to be taken into account, and the possibility of newly developed technologies should
also be considered.

c. Possible additional resources to meet other needs. Besides the flexibilty and capacity needs described above, Bonneville may need addi tional resources for a
number of reasons. These include Bonnevi lle’s proposal to ac quire resources to augment the existing system to serve the “high water mark” load of its preference customers at tier 1 rates; additional energy resources, if needed, because
customers call on Bonneville to meet their load growth; at tier 2 rates reflecting the costs of the additional resources; addi tional resources to se rve DSI loads, if
Bonneville decides to offer such servi ce; additional resources necessary for system reserves, system reliability, a nd transmission support; and additional
resources to assist the Administrator in meeting Bonneville’s fish and wildlife obligations under Section 4(h) of the Northwest Power Act. Conservation resources will help reduce the need for a dditional resources, but may not address
all of these needs. Th e Council is not undertaking at this time a detailed, quantitative assessment of Bonneville’s n eed for additional resources for any of these reasons, but will work with Bonnevi lle to identify if th ese needs exist and
whether and when additional resources s hould be acquired. In making decisions
about additional resources for these reasons , Bonneville should act consistent with the principles set forth in Chapter 12 and with the details in the relevant resource chapters of the plan.

BPA-4. Proper financial incentives for customers. Bonneville should meet the loads placed on the agency by its customers and ensu re system reliability with the existing federal base system, acquire conservation res ources and, if necessary, acquire additional generating resources consistent with the power plan and with Bonneville’s regional dialogue policy and tiered rates methodology. Bonneville resource acquisitions to meet customers’ loads above their “high water ma rks” should be structured so that these
customers bear the financial risk as sociated with such acquisitions.

BPA-5. Focus on preserving the FBS. Bonneville should c onduct its business in a way that will preserve the benefits of the FBS for the region.

BPA-6. Fish and wildlife. Bonneville should meet its fi sh and wildlife obligations.

BPA-7. Implement the regional dialogue policy. Bonneville should implement the policy choices it has made in adopting tiere d rates, signing long-term contracts, andAction Plan Sixth Power Plan

AP-18 revising its residential exchange program in ways that will allow the agency to achieve the goals identified in the various regional proc esses that established Bonneville's future
role.

BPA-8. Solve legal challenges to regional dialogue implementation. Bonneville should be prepared to take all necessa ry steps to revise those polic y choices, as necessary, if the
Ninth Circuit rules that the choices or some aspects of the choices must be overturned. Bonneville should be prepared to engage the region in any such revisions. If Bonneville’s policies fo r tiered rates, the residential exchange program (including the average system cost methodology), long-term contracts and related matters are struck down by the Ninth Circuit, Bonneville should in itiate regional efforts to bring those policies into line with the court’s decision( s) or, if necessary, after exhausting legal remedies, seek a legislative solution to enab le the agency to achieve the goals those policies were intended to reach.

BPA-9. Conditions if considering service to the DSIs . If the Administrator decides to offer service to the DSIs, consistent with any court rulings, such service should include the reserves required under the Northwest Po wer Act and provide, so far as possible, additional ancillary services.



## ENSURING ADEQUACY

Developing and adopting regional adequacy sta ndards was an important accomplishment of one of the key action items in the Council’s Fifth Po wer Plan. It not only protects against future energy or capacity shortages by pr oviding an early warning system, it also helps ensure that fish and wildlife operations are reliably implemented. The action plan is intended to ensure that the Council, working with others in the region, comple tes an annual assessmen t using the standards, but also that the Resource Adequacy Forum c ontinues to refine and update the standards to reflect new information and adjust to changi ng conditions. In addi tion, an action item is included to enhance the region’s ab ility to assess the adequacy of flexibility resources for within hour wind integration and system balancing.

ADQ-1. Adequacy Assessment. The Council, in collabor ation with the Northwest Resource Adequacy Forum and others, will annu ally assess the adequacy of the regional power supply.

ADQ-2. Data Review. The Council, in collaborati on with the forum and others, will annually review demand and resource data used for the adequacy assessment, compare its results with other regional reports and work to sta ndardize data reporting.

ADQ-3. Methodology Review. The Council, in collaborati on with the forum and others, will periodically review the Pacific Northw est’s adequacy standard and the methodology used to define the standard. If warranted, the Council will amend the standard.

ADQ-4. Working with other regions. The Council will monitor adequacy assessment methodologies in other regions and work w ith the Western Elect ricity CoordinatingAction Plan Sixth Power Plan

AP-19 Council to incorporate Pacific Northwest ade quacy metrics and assessments into Westwide adequacy reports.



## DEMAND RESPONSE

Power systems are required to maintain resources to meet extreme peak-load events. Some of these resources are seldom used and therefore ar e very expensive on a per kilowatt-hour basis if significant capital costs are invo lved in building the capability. A growing alternative is demand response, which allows voluntary reductions in load during extreme load events or interruptions of generation or transmission. The action plan for demand response includes increasing our understanding of demand response potential and cost-e ffectiveness. This involves monitoring implementation of demand response in the Pa cific Northwest and other areas where more demand response programs have been tested, suppor ting pilot programs to test demand response approaches, and exploring the potential of demand re sponse as a source of system flexibility for within-hour balancing reserves.

DR-1. Inventory demand response programs. The Council should compile and maintain an inventory of demand response acquisition programs and pilot programs that are active or in the planning stages in the region. The objective is to encourage communication among planners and administrators of these efforts at early stages in the work so that experience is shared and unn ecessary duplication is avoided as much as possible.

DR-2. Evaluate and demonstrate demand response programs. Utilities and regulators should consider not only pilots that test implementation strategies and demonstrate effectiveness of programs that have been successful elsewhere (e.g. direct load control of space heating or air conditioning), but also pi lots that explore innovative programs that have little or no history, but have promise (e.g. use of demand response from dispatchable electric water heater s to provide load following and/or wind integration).

DR-3. Evaluate potential for providing ancillary services. The Council, the region’s utilities, and regulators should examine demand response as a source of ancillary services, including estimation of potential megawatts availa ble, its cost and costeffectiveness.

DR-4. Monitor new programs. The Council, the region’s utilities, and regulators should monitor new programs to obtain dema nd response, including Bonneville’s pilot programs and the aggregator contracts of P acifiCorp, Portland General Electric, and
Idaho Power.

DR-5. Monitor experience in other regions. The Council, the region’s utilities and regulators should monitor progress outside the Pacific Northwest on demand response.

DR-6. Evaluate direct service industry as a source of demand response. If Bonneville serves direct service industry loa d, it should analyze all possibilities for using this load to provide reserves as required in the Power Act. In particular, the potential for this load to provide ancillary services shoul d be examined for its cost-effectiveness.Action Plan Sixth Power Plan

AP-20 DR-7. Complete the work of the PNDRP. Council should continue coordinating with the Regulatory Assistance Project, of th e Pacific Northwest Demand Response Project (PNDRP). In particular, PNDRP should comple te examination of pricing strategies to stimulate demand response.

DR-8. Include appliance response controls in standards. The region should advocate appliance standards that include Smart Grid controls to inte rrupt load (at least for under frequency events and utility calls). This action item could be included in energyefficiency action items A ppliances could include:

a. Water heaters (mixing valve as well as smart thermostat switch)
b. Clothes dryers

c. Refrigerators
d. Freezers

e. Air conditioners

DR-9. Implement demand response recommendations of NEET. The final recommendations of the Northwest Energy E fficiency Taskforce are likely to provide suggestions on how to develop demand respons e in the region. These recommendations should be pursued by the region.

DR-10. Improve Council modeling of demand response. The Council should examine the treatment of demand response in its regiona l portfolio model to ensure that the model properly captures the benefits a nd costs of demand response. To the extent that demand response has benefits that are difficult or impo ssible to simulate with the portfolio model, such as the benefits of demand response provi ding ancillary services, the Council should work with other parties to identify alternat ive analytical approaches to estimate these
benefits.



## SMART GRID

Smart-grid technologies have th e potential to transf orm the operation of the power system in ways that are difficult to predict, but that hold great potential for improved operations and reliability, and for making electr icity consumers partners in ma intaining the efficiency and reliability of the power system. These technol ogies are in their infancy and will take time to develop to full potential. To better understand smart-grid potential, the action plan supports regional pilot programs to gain experience with sm art-grid technologies and the role they might play in the power system.

SG-1. Monitoring smart grid technology. Monitor development and adoption of smart grid technology for its benefits and cost-effectiveness.

SG-2. Smart grid demonstration. Evaluate smart grid de monstration projects and develop additional demonstration projects when appropriate.

SG-3. Develop evaluation methods. Develop methodology for evaluating demand response used for ancillary services.Action Plan Sixth Power Plan

AP-21 

## TRANSMISSION

When the Council developed the Fifth Power Pla n, there was reason to be concerned about the transmission system. There had been no progr ess on improving the operation of the transmission system and little activity in planning for transmission system expansion. To a large extent, this is no longer the case either in the region or in the broader West ern interconnection. The Council will continue to participate in WECC activi ties relating to wind integration, transmission planning, and adequacy assessment. Bonneville is moving ahead with critical transmission expansions within its balancing area, and there are several large transmission projects in various stages of planning by other utili ties or merchant transmission pr oviders that would affect the Northwest. The action plan encourages conti nued regional efforts to improve wind integration capability through improved operational proce dures such as reserve sharing, dynamic scheduling, improved wind forecasting, and the ab ility to curtail wind ramps under extreme
conditions.

TX-1. Participate in and track WECC activities. Many of the actions that the Council is interested in, e.g., integr ation of large amounts of inte rmittent renewable generation, expansion of the transmission system to accommodate this generation, and development of resource adequacy assessments and guide lines, are affected by WECC actions.

a. Wind: Variable Generation Subcommittee (VGS). The VGS was formed in early 2009 to coordinate WECC actions a nd information sharing (both internally and with the actions of WECC members) regarding intermittent generation, especially wind and solar. Many of the actions needed to in tegrate large amounts of intermittent generation into the system n eed to take place, or are more effective if they take place, on a wider scale than ju st in the Northwest. Examples include: changes in business practices like schedu ling (e.g., to greater frequency than every hour), standardizing protocols for dynamic scheduling, and developing detailed operating dynamics models of wind generation.

b. Resource Adequacy: Loads and Resources Subcommittee (LRS). LRS develops WECC resource adequacy guideli nes and assessments and acts as the
interface with NERC in these areas and on NERC’s development of standards in the resource adequacy area. The WECC and NERC activities provide the background within which the Council analy zes adequacy issues and approaches and develops assessments.

c. Transmission: Transmission Expa nsion Planning Policy Committee (TEPPC). Coordinated transmission planning for larger scale projects needed to move distant, typically renewable, genera tion to load centers takes place primarily in two forums: subregional planning groups (SPGs) like Northern Tier Transmission Group and ColumbiaGrid and interconnection-wide, through TEPPC. TEPPC provides data and overall scoping studies for the SPGs and other entities like the Committee on Regional Electric Power Cooperation (CREPC)
and the Western Governors’ Association (WGA). TEPPC is expected to receive substantial funding from DOE under the Am erican Recovery and Reinvestment Act of 2009 (ARRA) to develop an inte rconnection-wide transmission plan, which will substantially expand the scope of its current activities.Action Plan Sixth Power Plan

AP-22 TX-2. Track transmission expansion proposals and evaluate impact on the region. This effort focuses on monitoring the status of transmission propos als that would have significant effects on the ability of regional utilities to develo p resources, particularly to import renewables, and to access regional and other markets.

TX-3. Continue to assess needs and costs of transmission for wind development.



## FISH AND POWER

The Council’s Columbia River Basin Fish and Wildlife Program and Electric Power and Conservation Plan must provide measures to “p rotect, mitigate, and enha nce fish and wildlife affected by the development, operation, and management of [hydropower] facilities while assuring the Pacific Northwest an adequate, effi cient, economical, and re liable power supply.” In other words, the mutual impacts of fish and power measures are intended to be examined together. By statute, hydroelect ric operations to improve fish surv ival that are specified in the fish and wildlife program become a part of the power plan and the plan must be designed to accommodate these operations and their cost. Guided by the Council’s power plan, Bonneville is to acquire resources to assist in meeting the requirements of the fish and wildlife program.

The action items listed below are designed to improve the way in which we plan for the longterm needs of both power and fish and wildlife. The key action is for power planners to work more extensively with fish and wildlife managers to explore ways to better identify and analyze long-term uncertainties that affect all elements of fis h and power operations. These
uncertainties include climate c hange, electricity demand, fuel prices, policies involving resource operation, and treaties affecti ng the hydroelectric system. Discussions should provide an opportunity to identify synergie s that may exist between power and fish operations and to explore ways of taking advantage of those situations. Another crit ical topic for discussion is the integration of variable generation resources, it s affect on the operation of the hydroelectric system and possible conseque nces for fish and wildlife.

F&W-1. Long-term planning coordination. The Council will work with federal, state, tribal, and other entities through existing fo rums to expand the discussion of long-term fish and wildlife and power planning integration.

F&W-2. Contingency plans. The Council will continue to work with fish and wildlife managers and regional power planners to: 1) review curtailment plans for fish and wildlife operations in the even t of a power emergency; 2) review contingency power operations in the event of a fi sh and wildlife emergency; and 3) aid in developing a plan to improve our ability to forecast and opera te the hydroelectric system to reduce the likelihood of emergencies.

F&W-3. Analytical capability. The Council will work with Bonneville and other federal action agencies, federal and stat e fish-and-wildlife agencies and tribes, and other regional entities (in particular the Independent Economic Analysis Board, the Independent Scientific Advisory Board, and the Independent Scientific Review Panel) to analyze the physical, economic, and biological impacts of alternative operat ions for fish and wildlife and to develop ways of improving the cost-effec tiveness of fish and wildlife programs.Action Plan Sixth Power Plan

AP-23 F&W-4. Columbia River Treaty. The Council will work with Bonneville and others to examine the impacts of possible changes to the Columbia River Treaty between the United States and Canada. The system flood cont rol elements of the treaty expire during this plan’s study horizon, and possible modifi cations to both the flood control and power supply aspects of the treaty could likely a ffect both the region ’s power system and operations to benefit fish and wildlife. Th e Council should be proactive in addressing
this issue.

F&W-5. Climate change. The Council will work with fede ral agencies, the University of Washington’s Climate Impacts Group, and othe rs to examine the physical impacts of climate change to electricity demand, river flows, reservoir elev ations, power production, and cost. The Council will examine ways to mitigate these impacts and encourage others to improve runoff volume forecasting methods, especially for the fall. The Council will also work to develop methods that include the potential physical impacts of climate change into its resour ce planning methodology.



## MONITORING PLAN IMPLEMENTATION

The Council will monitor conditions in the region for significant changes that would affect the power plan. The region’s progress in implemen ting the resource strategy in the plan will be
assessed and a biennial monitori ng report will be prepared descri bing any significant changes in the assumptions underlying the plan. The m onitoring report also will assess resource development in the region including efficien cy acquisition compared to the Power Plan’s
recommendations.

MON-1 Biennial monitoring report. Council will monitor implementation of the
recommendations in the Sixth Power Pl an and report on progress biennially.

MON-2 Assess changing conditions affecting the plan. Council will monitor how developing electricity load, fu el price, electricity pri ces, conservation technologies, resource costs, and other planning forecasts and assumptions compare to assumptions
included in the Sixth Power Plan.

MON-3 Analyze changes for significance. The Council will conduc t analysis of specific changes or issues to determ ine their effects on the regional power system and the Power
Plan.

MON-4 Monitor climate change policies and analysis. Continue to monitor progress in climate change models and their assessments of impacts on temperat ure, precipitation and stream flows. As the need arises, analyze specific climate change scenarios and assess potential effects on the plan's resource strategy.



## MAINTAINING AND ENHANCING COUNCIL’S ANALYTICAL
CAPABILITY

The Council’s power plan is extremely data and m odel intensive. Maintaining data on electricity demand, resource development, energy prices, a nd generating and efficiency resources is a significant effort. It is one that the Council’s staff cannot do alone. As recognized in the NEETAction Plan Sixth Power Plan

AP-24 recommendations, data collection for the regi onal power system and alternative resources available to meet demand is something best accomplished through regi onal cooperation. The action plan contains recommendations to mainta in and improve planning data for the region.

ANLYS-1. Review analytical methods . As is customary between power plans, the Council will undertake a comprehensive review of the analytic methods and models that are used to support the Council’s decisions in the power plan. The goal of this review is to improve the Council’s ability to analy ze major changes in regional and Bonneville Power systems and make recommendations on how the BPA Administrator can best meet its obligations and ensure a low-cost, low-risk power system for the region. This review will focus on changing regional power system conditions such as capacity constraints, integrating intermittent resources, and tran smission limitations because these currently pressing issues will need to be more forma lly addressed in future power plans. The
Council will work with Bonneville and other u tilities to evaluate available data and models that can be used to support the Counc il’s planning. This ac tion item will require the Council to clearly define the planni ng problems facing BPA and the region and identify or develop new analytic tools that can help the Council to identify the best possible approaches to meet the region’s and BPA’s future power needs.

ANLYS-2. Improve hourly load data. Work with utilities and NWPP to standardize collection of regional hourly loads data. Curr ently there is a substantial lag in getting regional hourly loads from NWPP. In fact, the last year of hourly data from NWPP is for 2002. This situation creates problems for updating the short-term forecasting model which is used for resource adequacy work.

ANLYS-3. Improve irrigation sales reporting. Work with utilitie s to receive irrigation sales data annually. Currently, there is a subs tantial problem with getting accurate data on irrigation sales in the region. This problem is more pronounced when it comes to public utilities. This problem has b een solved in the past by Counc il staff devoting a substantial
amount of work to contact individua l utilities and obtain the data.

ANLYS-4. Improve industrial sales data. Work with utilities to improve industrial sector sales data. Currently, industrial sales are reported by utilities to FERC and EIA in an aggregate fashion. Reporting sales data at a more disaggregated industrial level would improve the ability to forecas t loads. Confidentiality conc erns should be addressed and
solved.

ANLYS-5. Follow up on NEET data recommendations. There are other “data holes” where updating information would substantially benefit the region. Some of these data
needs were identified in the NEET recomme ndation from workgroup 1. An action item would be to track and implem ent NEET recommendations. Examples of data holes are:

a. End-use hourly load shapes
b. Energy use for end-uses (ICE)

c. Establishing panel data for residential a nd small commercial, especially elder care
facilities.
d. Improve the baseline consumption and c onservation potential for data centers

ANLYS-6. Improve electricity end-use data. Work with NEEA, RTF and utilities to:Action Plan Sixth Power Plan

AP-25 a. Develop a common survey and da ta gathering instrument
b. Develop the requirements for a data clearinghouse

c. Develop the data gathering cycles for each sector/measure
d. Coordinate the data gatheri ng implementation plan for 2010-2015

ANLYS-7. Improve peak-load forecasting. Facilitate a discussion among regional forecasters and others on peak-load for ecasting methodologies used in the region.

ANLYS-8. Improve natural gas demand forecasting. Work with regional gas utility demand forecasters to fine-tune gas forecasting capabilities of the load forecasting model

ANLYS-9. Develop the supply side of the demand forecasting system. Work with BPA to integrate the electric supply module of long-term forecasting model with the current demand forecasting model. This integration s hould enhance the Counc il’s ability to see the impact of various policies in a more cohesive manner.

ANLYS-10. Improve transportation electricity use forecasting. Enhance the electric transportation segment of th e long-term model for better representation of potential demand and impact on electric supply from the plug-in hybrid electric vehicles.

ANLYS-11. Demand response modeling methods. Work with BPA and others to incorporate the framework for modeling DR in the long-term forecasting model.

ANLYS-12. Evaluating sustained-peaking capability of the hydroelectric system. Work with others in the region, in particular the Resource Adequacy Forum, to develop a better methodology to assess the sustained-peaking capability of the re gional hydroelectric system.

ANLYS-13. Improved demand response modeling. The Council should examine the regional portfolio model’s treatment of dema nd response in case there are opportunities for improvement (see Action Item DR-9).

ANLYS-14. Planning coordination and information outreach. The Council will continue to participate in the deve lopment of Bonneville’s Res ource Program and in utility integrated resource planning efforts. In addition, the Council will periodically convene its planning advisory committees includi ng the Natural Gas Advisory Committee,
Conservation Resources A dvisory Committee and Genera ting Resources Advisory Committee for purposes of sharing informati on, tools, and approaches to resource planning.

ANLYS-15. Improve Regional Conservation Resource Potential Assessment Input Assumptions and Methodology. The Council will convene Conservation Resources Advisory Committee to identify data and met hodological requirements that are required to support regionally consistent utility or sub-regional assessment s of the conservation resource potential. The Council, in coopera tion with NEEA, BPA, regional utilities, and administrators of system benefit charge programs will seek to prioritize that market research and data development necessary to implement improvements in both the Council and utility conservation potentials assessments.Action Plan Sixth Power Plan

AP-26 ANLYS-16. Review of Council Policy on Direct Use of Natural Gas. The Council was unable to complete the analysis of the economics and emissions impacts of the direct use of natural gas prior to the re lease of the draft Sixth Power Plan. Due to the significant regional interest in this analysis, the Council believe s it should provide adequate opportunity for review and comment on the inpu t assumptions and results of this work before considering changes to its current policy. Therefore, the Council will complete this analysis during the first six mont hs of 2010 during which time it will conduct a public review process to cons ider any policy changes and action items related to its findings.

ANLYS-17. Incorporate conservation acquisition risk. Council staff began the modification of the resource por tfolio model to reflect unc ertainty about conservation
achievement rates. The revisions will be co mpleted as an action over the next year, so that conservation uncertainties can be treated similarly to other resource risks in the Council’s analysis. For the Si xth Power Plan, the Council ha s treated this uncertainty through scenario analysis.Sixth Northwest Conservation and Electric Power Plan 

# Chapter 1: Introduction

Purpose of the Power Plan ...................................................................................................... ........ 1 Major Issues................................................................................................................... ................. 3 Climate Change................................................................................................................. .......... 3 Providing Capacity and Ancillary Services ................................................................................ 4
Bonneville’s Role.............................................................................................................. .......... 5 Changing Technologies .......................................................................................................... .... 6 Growing Cost of Energy ......................................................................................................... .... 7
Historical context............................................................................................................. ............... 7 Electricity Demand ............................................................................................................. ........ 8 Electricity Generation ......................................................................................................... ...... 10 Energy Cost Trends............................................................................................................. ...... 12
A Vision for the Sixth Power Plan.............................................................................................. .. 14



## PURPOSE OF THE POWER PLAN

The Northwest Power and Conservation Council (C ouncil) was formed by the Northwest states
in 1981 in accordance with the Pacific Northwes t Electric Power Planning and Conservation Act of 1980 (Act). Each state’s governor appoint s two members to the Council making eight members in total representing Washington, Or egon, Idaho, and Montana. The Council was formed to give the Pacific Northwest states and the region’s citizen s a say in how growing electricity needs of the region would be provide d. The Act charges the Council with creating a power plan for the region. The purpose of the C ouncil’s power plan is to ensure an adequate, efficient, economical, and reliable po wer supply for the Pacific Northwest 1

.
The Act also recognized that development of the region’s hydropower dams had detrimental effects on migratory fish and wildlife and require d the Council to develop a program to mitigate those effects. The fish and wildlife program is an integral part of th e Council’s power plans.

The Council’s power plan and the fish and w ildlife program are developed through an open, public process to involve the region’s citizens an d businesses in decisions about the future of these two interdependent aspects of the Pacifi c Northwest environment and economy. The Act grants different approaches for these two Council responsibilities. The fish and wildlife program is based on, and defers to, recommendations fr om fish and wildlife agencies and tribes. However, the power plan is developed thr ough Council analysis, help ed by scientific and statistical advisory committees.

The power plan develops a strategy for the region to meet its future electricity needs. The Act recognizes that the demand for electricity is deri ved from the need for services electricity can provide, such as heat for homes, lights for commercial buildings, or motors for industrial processes. These services are the focus of the power plan. Technologies that allow production of these services more efficiently are the equivale nt of generating additiona l electricity. In fact, the Act designates efficiency improvements as the highest-priority resource for meeting electricity demands and gives it a 10 percent cost advantage. Second priority is renewable

1 Public Law 96-501, Sec. 2(2).Chapter 1: Introduction Sixth Power Plan

1-2 resources followed by high-efficiency genera ting technologies and then other generating technologies. 2 Except for efficiency improvements, the pr iorities of the Act are only tie breakers when alternative resources have equal cost.

The power plan includes a resource strategy to ensure demand for electricity is met by a combination of improved efficiency and generati ng resources that minimizes the cost of the energy system, including quantifiable environmen tal costs. Because th ere are many unknowns in the future, the power plan considers how co sts might vary with changing conditions and identifies strategies to reduce th e risk of high-cost futures. Th e action plan identifies specific actions needed in the next five years for the region to achieve the long-term strategy. These actions are the heart of the power plan because they set an agenda for the next several years.

The Act requires that the Council’s power plan be reviewed at least every five years. This power plan is the sixth produced by the Council since the Act was passed. In each plan, costs and technologies have changed resulting in subtle ch anges in the plans. Ge nerating technology costeffectiveness has shifted away from large coal an d nuclear facilities towa rd shorter-lead-time, more flexible, gas-fired genera tion. Recently, climate concerns and related state regulations have made renewable generation technologies more attractive.

However, consistently in all of the Council’s pow er plans, efficiency improvement has been the lowest-cost resource. As the Council’s ability to assess risk has gr own more sophisticated, efficiency also has proven to be the least-risky resource alternative. As a result, in each of the Council’s plans energy efficiency ha s been identified as an important resource for the region. In the Council’s first plan, conservation was expected to meet half of the region’s 20-year, mediumhigh load growth to 2002. In successive plans, the amount and share of conservation varied as utility programs or codes and standards captured some of the potential, new technologies became available, and cost-effectiveness levels changed. But the share of expected new energy resources to be provided by efficiency improvements never fell below 25 percent, and has typically been between 30 percent and 40 percent.

Over the years since the Council was formed, cons ervation has met nearly half of the region’s growth in energy-service demand. If the regi on’s energy savings were added back to the regional energy loads, load would have incr eased by 8,150 average megawatts between 1980 and 2008. During that time the region acquired 3,900 av erage megawatts of conservation, so that actual loads to be met by electricity genera tion only increased by 4,250 average megawatts.

In addition to the resource strategy, the Council’s power plan addresses si gnificant issues facing the Northwest power system and provides guidan ce to the region on addressing those issues. The focusing issues have changed with each pow er plan. The region’s power system has gone through many changes over the 28 years of the C ouncil’s existence, incl uding changes to the operation of the power system to aid fish and wildlife; electricity i ndustry restructuring; a changing role for the Bonneville Power Administ ration, the federal power-marketing agency that implements the Council’s power plan; and evol ving environmental concerns. The Council’s power plans have reflected those changing conditions.

A constant focus through all of the Council’s po wer plans has been the significant uncertainty facing the regional power system. In early plans, long resource lead times for coal and nuclear

2 Public Law 96-501, Sec. 4(e)(1).Chapter 1: Introduction Sixth Power Plan

1-3 plants created risk in the face of highly uncertain load growt h. Over time, other risks became a larger part of the problem in cluding fuel prices and availabi lity, industry restructuring, and environmental risks. Although the regional power system has changed in many ways from what was envisioned in the Act, the basic planning gu idelines have proven resi lient and continue to provide guidance to the region.



## MAJOR ISSUES

The regional power system is facing significant ch anges. The Sixth Power Plan addresses these changes through its resource recommendations and action plan. Some of the most important changes include:

• Growing concern about, and evolving policies to address, climate change

• Increased importance of assessing the capacity of the power system to meet periods of sustained peak electricity needs and provide ancillary services to meet system operation and wind integration requirements

• The changing role of the Bonneville Power Ad ministration in providi ng resources to meet the growing needs of public utilities

• Emerging technologies and incentives with th e potential to change significantly the relationships among electricity produ cers, utilities, and consumers

• Significant increases in the price of natural gas, oil, and coal supplies



## Climate Change

Concerns about climate change have changed the power planning landscape dramatically. Regardless of one’s beliefs about the causes of climate change there is a wide consensus among scientists and policy-makers that human-caused greenhouse gas emissions are contributors.
These concerns have resulted in a wide variet y of polices throughout the world, the nation, and
the Pacific Northwest and western states. Thes e policies are affecting the resource choices available for electricity generation both dir ectly through restrictions on certain types of resources, and indirectly through incentive progr ams to encourage certain types of resources. 3

An example of these policies is restrictions on ne w coal-fired power plants. In some cases these restrictions are direct prohibitions against ne w power plants emitting more than a determined amount of carbon. In others, it is regulatory or public resistance. But in any case, new conventional coal-fired power plan ts appear unlikely to be an alternative in the Northwest’s
future.

Renewable portfolio standards in Montana, Oregon, and Washington will require that a substantial portion of utilities’ added electricity generation will be from renewable resources. By 2030, the shares of loads that must be met from renewable technologies are: 15 percent in

3 See Chapter 11 for a discussion of these policies.Chapter 1: Introduction Sixth Power Plan

1-4 Montana, 25 percent in Oregon, and 15 percent (by 2020) in Washington. The timing to reach these levels varies by state. Ma ny other states in the West have similar renewable requirements.

Some policies already are in place. However, that does not mean they will remain unchanged. Policies can be reassessed and refined. Further, the Western Climate Initiative (WCI), an effort of 11 U.S. states and Canadian provinces to address climate issues, has set greenhouse-gas emissions goals and designed a market-oriented cap-a nd-trade process to facilitate meeting their goals. Participants in the WCI may have indi vidual goals to reduce greenhouse gas emissions. Such initiatives are often accompanied by a host of state policies to help reach the goals. The U.S. has yet to act at the national level on gree nhouse gas policies althoug h legislation is being actively considered. The carbon-re duction goals of these policies vary but typically would imply about a 40- percent reduction from 2005 levels of emission by 2030, and an 80 percent reduction from 2005 levels by 2050. The result of all these f actors is simply that many future policies that could profoundly affect resource choices rema in unknown, creating risks for resource decisions
that have to be made now.

Uncertainty about climate policie s raises several questions for the Sixth Power Plan. These
include:

• What are likely costs of carbon-control polic ies, and will those costs be known (carbon tax) or unknown (cap-and-trade system)?

• What is the lowest-cost approach to mee ting carbon emissions reduction targets, and what are those targets most likely to be?

• What are the costs of renewable resources, a nd what will be the costs to consumers of meeting renewable portfolio standards?

• How will development of renewable generation affect the operation of the power system
and the need for new transmission investments?

• Are there carbon-control policies in other se ctors, such as transportation or building construction and maintenance, that will affect the need for electricity?

• Will uncertainty about future carbon policies and their effects on energy costs lead to inadequate investment in electricity supplies?



## Providing Capacity and Ancillary Services

Until recently, the Pacific Northwes t was able to plan its power system based on average annual energy needs and supplies. The hydroelectric sy stem provided a large share of the regional electricity supply and had the flexibility to provi de most of the peaking and shaping (ancillary services) required to match reliably electricity generation to consumption on an annual, seasonal, hourly and sub-hourly time scale.

The hydroelectric system, however, can no longer be assumed to provide all of these services. There are several reasons for this change:Chapter 1: Introduction Sixth Power Plan

1-5 o First, the seasonal patterns of electricity demand in the region are changing as air conditioning use has grown.

o Second, flexibility of the hydroelectric system has been constrained by actions taken to help mitigate for its impacts on fish and wildlife.

o Third, the share of non-hydroele ctric generating resources has been growing over the last 40 years and those resources typically do not ha ve the same degree of flexibility as the hydroelectric system.

o Finally, the region has added significant amount s of wind generation, which is a variable resource and adds to the shaping and flex ibility requirements of the power system.

Assuring an adequate and reliable power syst em increasingly requires addressing the peaking and shaping capability of the power system. This power plan, for the first time, addresses these
issues.

• What is the capacity of the hydroelectric system to meet peak loads and provide flexibility resources?

• Are there actions that can reduce the need for additional capacity and flexibility?

• What other resources can provide such services and what are their costs?

• What mix of generating resour ces, energy storage, and demand-side response is most cost-effective for providing needed flexibility?



## Bonneville’s Role

More than 10 years ago, the Comprehensiv e Review of the Northwest Energy System
recommended that Bonneville should focus on ma rketing the existing res ources of the federal base system to protect its low cost and ensure regional commitment to repaying debt to the U.S. Treasury. 4 One of the review’s basic tenets was that utilities would pay the cost of new electricity supplies for growth in their custom ers’ demand beyond that provided through the existing federal base system.

Bonneville adopted its Regional Di alogue Policy in July 2007. S ubsequently, Bonneville and its customer utilities signed long-term contracts in 2008 to implement the po licy with the intention of protecting the cost-based federal system while providing better incentives for utility resource
decisions.

This change will empower many customer-owned u tilities to make their own resource decisions. In addition, many of these utili ties are now subject to planni ng requirements and renewable portfolio standards imposed by states in the region.

4 Comprehensive Review of the Northwest Ener gy System: Final Report. December 12, 1996.Chapter 1: Introduction Sixth Power Plan

1-6 As a result of these changes, implementation of the Council’s plan will become even more diverse. Bonneville’s role in developing future power resources for the region likely will be reduced. These changes pr ompt several questions:

• How will the region implement the Council’s power plan?

• Who will be responsible for meeting efficien cy goals, and how will achievements be
tracked?

• How will small customer-owned utilities deve lop resources to meet their load growth?



## Changing Technologies

The digital revolution has created technologies that could substant ially change the way the power system is planned and operated. These technolog ies offer the possibility for improved control, reliability, and efficiency of power system operations, an enhanced market for energy and ancillary services, and a greater opportunity for consumers and distributed generation to participate in the operation of the power system.

This general area of technology is fr equently referred to as the “smart grid.” Components of this technology include electric meters at homes and businesses that can be remotely monitored, saving utilities meter-reading costs, but also ot her sensor technology that can communicate back to the power system on the status of electricity use, the exact location of outages, and the status of the distribution system at all points in a utility’s system. This technology provides a foundation for automated demand response when coupled with appropriate price signals, consumer agreements, and end-use equipment controls.

The advancement and deployment of these technologi es is likely to significantly change the way in which improved efficiency is acquired. With da ta on each customer's us e at intervals of one hour or less, energy-savings estimates and evalua tions of conservation-acquisition alternatives
can be more confident. As better information about the value of electricity savings in particular locations and at particular times is made av ailable to consumers, efficiency improvements increasingly will be pursued as a business strategy. Energy service and management companies
will be able to offer a business case to consumer s that improves the quality and reduces the cost of electricity. This continues a trend of increasing role s for non-utility entit ies in the acquisition of energy efficiency. This trend has included the creation of the Northwest Energy Efficiency Alliance, the Energy Trust of Oregon, and numer ous energy-service companies. Pursuit of efficiency as a profitable business case may be the next stage of energy efficiency acquisition strategies. Technology advancements pose que stions for power planners, including:

• How will advancement of smart-grid technol ogies change the role of utilities and
customers?

• What actions are needed to facilita te development of these technologies?

• Are there barriers to expans ion of these technologies?Chapter 1: Introduction Sixth Power Plan

1-7 • Will smart-grid technologies and practices impr ove the reliability and efficiency of the electrical grid, or will diffusion of contro l create problems for management of the system?

• How will smart-grid technologies facilitate ot her objectives of energy or climate policy? For example, is it needed to integrate plug-in electric vehicles into the power system?



## Growing Cost of Energy

Since the Council was formed in 1981 there have b een two major incidents of electricity price increases. The first was just about completed as the Council was created and it was due to large
overinvestment in nuclear faciliti es that turned out to be unneed ed. The second large increase
occurred in 2000-2001 and was due to underi nvestment in electricity generation.

Current expectations are that the region faces a third increase in elec tricity costs, although perhaps it may occur over a more extended time peri od. In this case, the in crease will be due to increased cost of basic energy supplies, such as oil, natural gas, and coal, increased carbonemissions controls, and requirements to deve lop more expensive renewable sources of electricity.

Each historical increase in elec tricity prices changed the Northwes t economy and electricity use. The 1979-1981 increase pushed electricity-intensi ve industries of the region to marginal producers in world markets. The 2000-2001 increas e resulted in the perm anent closure of many of these regional industries. From the 10 alum inum plants that were operating in the region when the Act was passed, only three remain in partial operation. In a ddition, many other energyintensive industries have closed permanently in the last 10 years. The potential for higher future energy costs raises these questions:

• What additional effects will increasing electr icity prices have on the economic structure of the region?

• Are there strategies to reduce the effects of higher prices on the region’s consumers of electricity?

• Are there approaches to carbon-emissions redu ction that moderate the price increases?



## HISTORICAL CONTEXT

The Council’s power plan looks 20 years into the region’ s electricity future. Decisions regarding this future are long-lasting and have important effects on the adequacy, efficiency, reliability, cost, and environmental footprint of the power system. To plan for a future that ensures the region a resilient supply of elect ricity consistent with long-te rm growth and environmental sustainability, it is important to understand how th e regional electricity market has evolved. Anticipating changes that could take place during a period of 20 years requires investing in a power system that is as adaptable as possible.

This section provides background on trends in el ectricity demand and supply since the time the Council was created. It looks at changes that ha ve occurred during the past 25 years to provideChapter 1: Introduction Sixth Power Plan

1-8 important insights into the region ’s energy future. This section seeks to answer questions: How has the use of electricity grown a nd changed? What role has impr oved efficiency played in these trends? How have the sources of electricity ge neration changed over the years, and how have the institutions and regulations changed?



## Electricity Demand

The year 1980, the year the Northwest Power Act was passed, was a watershed for the region. In preceding decades, the region had experienced rapid growth in electricity demand. There was an expectation that this rate of demand growth would continue. Du ring this time, there was little hydroelectric expansion and many planned inve stments in large-scale coal and nuclear generating plants. The cost of these new ge nerating sources was much higher than existing hydroelectricity. Their development created a huge increase in electricity costs.

Instead of the ever-growing electricity dema nd experienced before 1980, the region found that demand was indeed responsive to price change s. The region’s aluminum plants, which accounted for nearly 20 percent of all regional el ectricity use, became far less competitive in world markets. But other users of electricity also responded by altering their consumption. Between 1960 and 1980 regional electricity loads grew at 5 percent pe r year, but in the subsequent 20 years from 1980 to 2000, load growth was only slightly over 1 percent per year. Slowed growth in demand and escalated costs of new power plants combined and forced many of the regional investments in new nuclear facilities to be abandoned. Unfortunately, many of their costs already were incurred and s till affect electricity prices today.

In 2000 and 2001, the region experienced a second la rge electricity price increase. Unlike the 1980 price increase, this one was a result of too little investment in electricity generation, combined with a poor water year and a flawed power-market design in California. This price
increase confirmed the demise of most of the re gion’s aluminum smelters and resulted in closure or cutbacks in other energy-intensive industrie s as well. Regional loads dropped by 16 percent between 1999 and 2001, falling back to levels of the mid-1980s.

Electricity prices and consumpti on are often compared to national statistics. Such comparisons help us understand regional long -term trends. The Pacific Northwest economy historically has been both more energy-intensive than the rest of the nation, and more el ectricity-intensive. However, the regional trends in total en ergy use per capita, and per dollar of economic production (Gross Domestic Product (GDP) or Gross State Product (GSP)), have been different
from the national trends in recent decades. National total energy use per capita flattened following the early 1970s whereas th e regional use of energy per capita declined. By 2006, the region’s energy use per capita and the nation’s were the same. National total energy use per real
dollar of GDP has declined since 1977 when the data first were av ailable. However, the Pacific Northwest’s energy use per real dollar of GSP dec lined faster, and has equaled the nation’s since
2001.

The Pacific Northwest remains more electricity intensive than the nation. That is, the share of electricity used to meet all energy needs is higher in the Northwest than it is in the rest of the nation. But that gap has narrowed significantl y since 1980. Until 1980 the regional share of end-use energy needs met by electricity, compared to other sources such as oil or natural gas, was nearly double the national sh are. Both the national and re gional shares grew between 1960Chapter 1: Introduction Sixth Power Plan

1-9 and 1980. However after 1980, the nati onal electricity share continue d to grow, but the regional share remained stable. By 2006, the regional el ectricity share in total energy consumption by households and business was 20 percent compared to a national share of 17 percent.

The greater electricity intensity of the Pacific Nort hwest historically was due in large part to the region’s electricity-intensive indus tries drawn here because of low- cost electricity supplies. The loss of some of these industries has significan tly reduced the region’s electricity demand. Not only has the region’s industrial use been electricity-intensive, the region’s residential and commercial energy use also historic ally has been more electricity-intensive than the rest of the
nation. The national electr ical intensity of these sectors has grown over the last 45 years, but the region’s intensity has re mained flat since 1980. Figure 1-1 s hows that the region’s per capita residential and commercial electricity demand has been higher but its rate stable, whereas the nation’s demand has been lower but is growing at a steady rate.

Figure 1-1: Residential and Commercial Electricity Use Per Capita: U.S. versus Region

0.00 5.00 10.00 15.00 20.00 25.00 30.00 35.00 40.00

1960 1963 1966 1969 1972 1975 1978 1981 1984 1987 1990 1993 1996 1999 2002 2005Billion Btu Per Thousand

US

PNW

Both regional and national electricity prices ha ve increased over the last 35 years. National prices increased following the oil embargo in 1973, but the region’s prices, which were less influenced by changes in oil and natural gas prices, did not escalate rapidly until 1980. During the 1980s and 1990s regional electric ity prices remained roughly half of national prices. With the price increases following the Western elec tricity crisis in 2000-2001, the gap closed some, but as shown in Figure 1-6, the region continues to have significantly lower prices than the
nation as a whole.

Although the nation and the region had similar el ectricity price growth, regional demand per capita stopped growing after 1980 wh ile the nation’s continued to gr ow. What accounts for this difference in response? Part of the explanation is the loss of electric ity-intensive industrial sectors. However, the pattern is also evident in the residential and commercial sectors. Part of the pattern can be traced to convers ions of space and water heat from electricity to natural gas. Other parts of the country already used natural gas for these services.Chapter 1: Introduction Sixth Power Plan

1-10 Another important factor limiting the region’s growth of electricity demand has been its efforts to improve the efficiency of electricity use. Since the Northwest Power Act in 1980, the Pacific Northwest has pursued programs to improve the efficiency of electricity use. By 2008, the region had saved 3,900 average megawatts of electric ity as a result of the accumulated effects of Bonneville and utility conservation programs, im proved energy codes and appliance-efficiency standards, and market-transformation initiatives. Figure 1-2 shows the effects of these savings over time. These efficiency improvements have me t 48 percent of the regi on’s load growth since 1980, and the savings now amount to more than th e total electricity use of Idaho and Western Montana combined. Without improved efficiency, the growth of regional electricity use would have been 1.5 percent per year from 1980 to 2008 instead of the 0.8-percent the region experienced during that time.

Figure 1-2: Effects of Conser vation on Growth of Demand

0 5000 10000 15000 20000 25000 30000

198

0 1982 198 4 1986 1988 1990 1992 1994

1 996

1 998 2 000 2 0 0 2 2 0 0 4 2 0 0 6 2 0 0 8aMW

Conservation

Load

The region’s historical electricity use has impli cations for electricity demand forecasts. Because
fuel conversions and fewer electri city-intensive industrie s played an important role in the past stabilization of the electricity intensity of the P acific Northwest, it may be more difficult to offset growth in the future. Without aggressive conser vation efforts, electricit y demand may return to growing at the same rate as population and economic activity.



## Electricity Generation

A long-term view of electricity generation in th e Pacific Northwest reve als a trend of growing diversity of energy sources. In 1960, nearly all electri city was supplied from hydroelectric dams. As Figure 1-3 shows, growth in electric generati on needs has been met by other sources, such as coal, nuclear, natural gas, biofue ls, and most recently wind power. 5 These resources weren’t developed with diversity in mind; they were developed in phases based what was apparently most attractive at the time. Early diversific ation from hydroelectricity focused on coal and

5 Figure 1-3 shows average annual energy capability. The hydropower numbers are critical-water, and wind assumes a 30-percent capacity factor.Chapter 1: Introduction Sixth Power Plan

1-11 nuclear generation. In the late 1990s and early 20 00s natural gas was favored, and most recently wind has been encouraged by ec onomic incentives and state rene wable portfolio standards.

But not all growth in electricity consumption ha s been met by increased generation capability. Figure 1-3 shows conservation as part of the cu rrent mix of electricity generating resources.
Conservation is the fourth-lar gest resource meeting the Northw est’s electric energy needs, exceeded only by hydropower, coal, and natural gas.

Figure 1-3: Growing Electricity Resource Diversification in the Pacific Northwest

0 5000 10000 15000 20000 25000 30000 35000

1960 1980 2003 2008Average Megawatts Conservation

Other

Wind

Uranium
Natural gas
Hydro

Coal

Figure 1-4 shows the mix of elect ricity capacity in the region. 6 Capacity refers to the ability to produce energy during peak demand hours. Figure 1-3 shows contributions to “energy,” which refers to the sources of electricity used to m eet average demand over a year typically. Compared to the energy mix, installed cap acity shows much higher hydropower and wind shares. The left side of Figure 1-4 shows generati on only; the right side includes the effect of conservation on peak loads.

However, hourly capacity as shown in Figure 1-4 can be misleading for the assessment of adequacy of electricity supplies. For example wind is a variable resource and has very little dependable capacity value because its generati on cannot be counted on reliably over short periods of time. Likewise, the hydroelectric syst em’s capacity value must be reduced because of its limited ability to sustain energy production over several days of high loads. In both cases, the generation that can be counted on is limited by th e fuel supply -- that is , by the wind or, in the case of hydroelectric generation, by available water. In April 2008, the Council adopted a resource adequacy standard, which acts as an ear ly warning system to alert the region when the power supply can no longer reliably supply a nnual energy or peak capacity needs.

6 Figure 1-4 shows installed generating capacity of resources. Installed capacity is the maximum amount of energy that could be generated during a peak hour. Dependable capacity is the amount of energy that can be counted on in a peak load hour. In the case of wind generation, dependable capacity is only about 5 percent of the installed capacity shown in Figure 1-4. Conservation has been increased by the system load factor, that is peak energy consumption relative to average annual consumption.Chapter 1: Introduction Sixth Power Plan

1-12 Figure 1-4: Electrical Capacity Re sources in the Pacific Northwest

Biomass

Coal

Geothermal Hydro
Natural gas

Petroleum Pump Storage

Solar

Uranium

Wind

Conservation Natural
Gas

Hydro Coal Wind Conservation

Hydro Natural
Gas Coal W ind



## Energy Cost Trends

Energy, like many other commodities, tends to experience price cycl es. At the time the Council was developing its first power plan in the early 1980s, energy prices were at a high point. Oil prices were high due to OPEC po licies and war in the Middle East. Natural gas prices were high as a result of regulatory policies that impeded deve lopment of new supplies. Electricity costs in the Pacific Northwest had just experienced a huge increase due to overbuilding new nuclear generation capacity exacerbated by the high infl ation and interest rate s of the late 1970s.

In the mid-1980s fuel prices fell, but retail elec tricity prices in the region remained high. The new millennium brought another commodity price cy cle for oil, natural gas, and coal. For example natural gas prices, which had averaged $2 per million Btu in the 1990s, increased to an average of nearly $6 during the first decade of the new millennium. In addition, fuel prices have become more volatile. The wholesale market price of electricity is more closely linked to cycles in fuel prices than in the past because more of the region’s gene ration is based on natural gas and coal now. Figure 1-5 illustrate s these historical trends in fuel and electricity prices.Chapter 1: Introduction Sixth Power Plan

1-13 Figure 1-5: Energy Price Trends

0 10 20 30 40 50 60 70 80 90 100

1970 1972 19

74

1976 1978 1980 1982 1984 1986 1988 1990 1992 1994 1996 19

98

2000 2002 2004 2 006

2008$ Per Barrel and $ Per Ton

0.00 1.00 2.00 3.00 4.00 5.00 6.00 7.00 8.00 9.00$ Per MMBtu and Cents Per Kwh Crude Oil

Coal

Natural Gas Retail Electricity

In spite of price increases over the past 30 years, the cost of electricity to Pacific Northwest
consumers remains lower than costs to consumers in other parts of the country. In 2007, Idaho was the lowest-price state in the nation, Wash ington rated seventh-lowest, Oregon was 15th, and Montana 22nd. Taken together, reta il electricity prices in the four Northwest states in 2007 were
a little more than two-thirds of the national av erage, and only half of electricity prices in California. Although prices have increased s ubstantially since 1980, the Northwest still enjoys relatively low electricity prices.

Figure 1-6: Average Retail Elect ricity Prices by State, 2007

0.00 5.00 10.00 15.00 20.00 25.00

HI M A ME CA MD TX PA AZ MS NC M T OK T N KS IN WA KY ID US

MT OR WA ID CA

An important factor in Californi a’s higher electricity prices is the cost of resources for peak demand. California electricity demand is more vari able than in the Pacific Northwest. Peak electricity loads in California are about 70-percent higher than average annual electricity use. In comparison, peak loads in the Pacific Northwes t are typically 25 percent higher than averageChapter 1: Introduction Sixth Power Plan

1-14 annual electricity use. But more importantly, Ca lifornia uses fuel-based peaking resources to meet its requirements to a much larger extent than in the Pacific Northwest. The capital and fuel costs of these peaking resources must be recovered over very few operating hours a year when they are used to meet these periods of high dema nd. In the Pacific Northw est, the hydroelectric system provides much of the peaking capacity and ancillary services for the region at very low

cost.

The hydropower system’s use as a base resource and its inexpensive flex ibility together keep Northwest electricity prices low. As the regi on outgrows the hydropower system’s capability to provide peaking and flexibility, other resources w ill be necessary and the cost of electricity will likely increase. Preservation of the hydropower system’s flexibility and capacity is key to keeping Northwest prices low, and also to main taining a low carbon footprint. Developing costeffective demand response also can contribute to meeting peak loads and providing flexibility.



## A VISION FOR THE SIXTH POWER PLAN

For nearly 30 years, the Council’s mission – to assure the region of an adequate, efficient, economical, and reliable power supply, while also protecting, mitigating and enhancing fish and wildlife affected by the Columbia River Basi n hydroelectric system – has not changed.

The Northwest’s energy environment is complex, and this is a time of profound change. From concerns about the increasing cost of electricity to the effects of greenhouse gases on climate and the operation of the region’s hydroelectric and transmission systems to meet peak demand, integrate wind generation, and recover endangere d salmon and steelhead, the challenges are many, and they are interrelated.

The Council’s Sixth Power Plan recognizes and res ponds to this new environment. It lays out a strategy for moving toward the power system of the future while maintaining a reliable and affordable system.

How will these challenges be addressed, and what wi ll the energy system of the future look like?
The Council’s Sixth Power Plan envisions a clean er and more efficient system for the region,
with these attributes:

• Nearly 6,000 average megawatts of achievable en ergy efficiency that will greatly reduce the Northwest’s electricity demand and carbon- dioxide production over the next 20 years.

• Improved operation of the regional power sy stem that will help accommodate diverse and variable-output renewable generation and prom ote the efficient use and expansion of the regional transmission system.

• Conventional coal plants that will operate wi th effective carbon-re ducing technologies or be displaced by resources that emit less or no carbon.

• Smart grid and other technologi es that will make the ener gy system more efficient and decentralized, maintaining its reliability a nd safety, and potentially transforming power system operations. It will faci litate instant notification and location of outages, provideChapter 1: Introduction Sixth Power Plan

1-15 flexibility and energy storage, and help inte grate variable-output wind power and plug-in hybrid cars into the regional power system.

• A hydroelectric system whose capability is pres erved and improved in order to provide low-cost power for the region, providing both fl exibility to help integrate wind and other variable-output resources and improved conditions for salmon and steelhead.

• A regional power system that does its part through the above actions to achieve the carbon-reduction goals that have been adopted by three of the four st ates in the Pacific
Northwest.

• Access by Pacific Northwest citizens to better information about their electricity supply so that they can participat e in the formation and implementation of important regional policies.

Today, the road to this vision means addressing many new questions. The Sixth Power Plan is a map to that future.Sixth Northwest Conservation and Electric Power Plan 

# Chapter 2: Key Assumptions

Summary of Key Findings........................................................................................................ ...... 1
Introduction................................................................................................................... .................. 2
Economic Growth ................................................................................................................ ........... 2
Alternative Economic Scenarios................................................................................................. 4
Fuel Prices.................................................................................................................... ................... 5
Carbon Dioxide Prices .......................................................................................................... .......... 9
Renewable Portfolio Standard Resource Development................................................................ 10 Wholesale Electricity Prices ................................................................................................... ...... 12 Retail Electricity Prices...................................................................................................... ........... 16 History........................................................................................................................ ............... 16 Forecast of Retail Electricity Prices.......................................................................................... 17
Sector Retail Prices........................................................................................................... ........ 17



## SUMMARY OF KEY FINDINGS

Pacific Northwest population and ener gy costs are expected to increase over the next 20 years. Regional population is likely to increase fr om 12.7 million in 2007 to 16.7 million by 2030. This 4.0 million increase compares to a 3.8 milli on increase between 1985 and 2007. The population growth will be focused on older-age categories as the baby-boom generation reaches retirement age. While the total regional population is pr ojected to increase by over 28 percent, the population over age 65 is expected to nearly double. Such a large shift in the age distribution of the population will change consumption patterns and electricity use. Some possible effects could include increased health care, more retirement a nd elder-care facilities, more leisure activities and travel, and smaller-sized homes.

The cost of energy (natural gas, oil, and electricit y) is expected to be si gnificantly higher than during the 1990s. Although prices have decr eased significantly sinc e the summer of 2008, current levels, especially for natural gas, are depressed by th e effects of the recession. Nonconventional natural gas production has increa sed in the last few years, encouraged by higher prices. The technology to retrieve thes e supplies cost-effectivel y has been a recent development that continues to improve, making e xpectations for adequate future supplies more certain. Nevertheless, the cost of finding and producing these ne w supplies is higher than for conventional supplies, which increases the estimat ed future price trend for natural gas.

Carbon-emission taxes or cap-and- trade policies are likely to raise energy costs further. Wholesale electricity prices ar e expected to increase from about $30 per megawatt-hour in 2010 to $74 per megawatt-hour by 2030 (2006$). These el ectricity prices refl ect carbon costs that
start at zero and increas e to $47 per ton of CO 2 emissions by 2030. Higher electricity prices reduce demand, advance new sources of supply a nd efficiency, and make cost-effective more efficiency measures.Chapter 2: Key Assump tions Sixth Power Plan

2-2 

## INTRODUCTION

The Northwest Power Act requires the Council’s pow er plan to include a forecast of electricity demand for the next 20 years. De mand, to a large extent, is driven by economic growth, but it is also influenced by the price of electricity and other fuel.

The power plan treats energy efficiency as a re source for meeting future demand. In order to understand and properly assess its potential, demand forecasts must be developed in great detail considering specific uses of electri city in various sectors. Such assessments require significant detail in their underlying economic assumpti ons; the number and types of buildings, their electrical equipment, and their current efficiency levels are all critical to accurately assessing potential efficiency improvements.

Most of the assumptions and forecasts for the de mand forecast are also im portant for other parts of the power plan. For example, fuel prices a ffect not only electricity demand, but also the cost of electricity generation from natu ral gas, oil, and coal-fired powe r plants. Because of this, fuel price forecasts help determine th e wholesale electricity price and the avoided cost of alternative resources when considering the cost-effectiveness of improved efficiency. In addition, sectorspecific economic forecasts of building and appliance stocks, their expected growth over time, and their pattern of energy use over different seasons and times of the day are factors in determining efficiency potential and cost-effectiv eness. Basic financial assumptions such as rates of inflation, the cost of cap ital for investments by various enti ties, equity-to-debt ratios, and
discount rates are used thr oughout the planning analysis.

For many of these assumptions, ther e is significant uncerta inty about the future. That uncertainty
creates risk that is addressed in the Council’s power plan. Th ese risks and uncertainty include long-term trends, commodity and business cycles, seasonal variations, and short-term volatility.



## ECONOMIC GROWTH

Demand for energy is driven by demand for services needed in homes and places of work. In the long-term, the region’s economic growth is a key driver of demand. One general measure of the size of the regional economy is its population. As the regional population increases, the number of households increases, the number of jobs incr eases, and goods and services produced in the economy increase, all driving the ne ed for energy. This is not to say there is a one-to-one relationship between growth in the economy and growth in demand. Other factors, such as energy prices, technology changes, and increase d efficiency can all change the relationship between economic growth and energy use.

The residential demand forecast is driven by the number of homes and the amount and types of appliances they contain. Commer cial sector demand is determined by square feet of buildings of various types, and industrial demand depends on projections of industr ial output in several manufacturing sectors. The expected electr icity use in aluminum smelters is forecast independently. A brief overview of the forecast assumptions for each of the key economic
drivers of demand follows:

Population. Population in the Northwest states gr ew from about 8.9 million in 1985 to about 13 million in 2007, increasing at about 1.6 percent per year. The growth in population is projectedChapter 2: Key Assump tions Sixth Power Plan

2-3 to slow to about 1.2 percent annually, resulting in a total regional population of 16.7 million by
2030.

Homes. The number of homes is a key driver of de mand in the residential sector. Residential units (single family, multifamily, and manufactured homes) are forecast to grow at 1.4 percent annually from 2010-2030. The current (2008) stock of 5.7 million homes is expected to grow to 7.6 million by 2030, or approximately 83,000 new homes per year.

Appliances. In the residential sector, lifestyle choi ces affect demand. As more homes are linked to the Internet, and as the saturation rate for ai r conditioning and electronics increases, residential sector demand increases. Over 80 percent of a ll new homes in the regi on now have central air conditioning, and the growth rate in home electronics has been phenomenal--over 6 percent per year since 2000, and it is expected to conti nue growing at about 5 percent per year.

Commercial Square Footage. Demand for electricity in the commercial sector is driven by demand for commercial floor space that requires li ghting, air conditioning, and services to make occupants comfortable and producti ve. The square footage of commercial buildings is forecast to grow at 1.2 percent annua lly from 2010-2030. The current 2007 commercial building stock of 2.9 billion square feet is expected to grow to 3.9 billion square f eet by 2030, or at a rate of about 40 million square feet per year. A growing porti on of this commercial floor space is for eldercare facilities.

Industrial Output. The key driver of demand for the industrial and agricultural sectors is dollars of value added (a measur e of output) in each industry. I ndustrial output is projected to grow at 3 percent per year, growing from $83 billion (2006 constant dollars) in 2007 to $149 billion by 2030. Agricultural output, which drives ir rigation electricity use, is projected to grow at 3.2 percent per year, from $13 billion (2006 constant dollars) in 2007 to $25 billion by 2030.

Direct Service Industries. Demand for Bonneville’s direct se rvice industries (mainly aluminum smelting operations) is projected to be nearly constant, rising from 764 average megawatts in 2007 to 770 average megawatts in 2012, and then remaining constant from 2012 through 2030.

The main source of data for the economic drivers is HIS Global Insight’s quarterly forecast of the national and regional economy and Global Insi ght’s U.S. business demographic forecast. Third quarter 2009 data was used in developing the Council’s Si xth Power Plan. The Council’s financial assumptions, such as the inflation rate, are also drawn from the same economic forecast. Figure 2-1 shows both the historic and medium case growth rate assumed for the development of the Sixth Power Plan. In gene ral, the medium forecast reflects a slowdown in key economic drivers compared to the last 20 years. The imp act of the current recession was incorporated into the plan using Global Insight’s long-term October 2009 forecast.Chapter 2: Key Assump tions Sixth Power Plan

2-4 Figure 2-1: Comparison of Key Economic Drivers

0.0% 0.5% 1.0% 1.5% 2.0% 2.5% 3.0% 3.5% 4.0% 4.5% 5.0%

P

o

pu

l ati

o

n

R eside n tial

Co

mmerci a l F

l o

orspa ce

M

a nu

f a ct

u ri

n

g

O

u t p ut Mining Output

Agri c ultu r e Output

Tr

a nsportation



### 1985-2007 2010-2030



## Alternative Economic Scenarios

Three alternative scenarios are considered in th e demand forecast. In the medium-case scenario, the key economic drivers project a long-term, h ealthy regional economy (albeit with a slower growth rate than in the recent past). In additi on to the medium case, two alternative scenarios are considered: one representing a low-economic-g rowth scenario and the other a high-growth projection of the future. The low-case scenario reflects a future with slow economic growth, weak demand for fossil fuel, declining fuel pr ices, a slowdown in labo r productivity growth, and a high inflation rate. On the other hand, the high -case scenario assumes faster economic growth, stronger demand for energy, higher fo ssil fuel prices, sustained grow th in labor productivity, and
a lower inflation rate.

It is assumed in the medium, low, and high scen arios that climate change concerns and demand for cleaner fuel lead to a carbon tax, which pushes fuel prices to a higher trajectory. Table 2-1 summarizes the average growth ra te for key inputs in each of the alternative scenarios.Chapter 2: Key Assump tions Sixth Power Plan

2-5 Table 2-1: Historic, Medi um-Case, and Alternative S cenarios for Growth Rates

Key Economic Drivers 1985-2007 (Actual) 2010-2030 (Low) 2010-2030 (Medium) 2010-2030 (High) Population 1.60% 0.49% 1.20% 1.5% Residential Units 1.90% 0.49% 1.40% 1.5% Commercial Floor Space 2.30% 0.67% 1.20% 1.43% Manufacturing Output $ 4.10% 0.00% 1.70% 2.11% Agriculture Output $ 4.40% 3.0% 3.60% 4.2% Light Vehicle Sales - 2.52% 2.40% 3.05% Inflation Rate 2.20% 2.70% 1.70% 1.50% Average Annual Growth Rate in Price (2010-2030)*
Oil Prices 1.70% -1.00% 1.04% 2.30% Natural Gas Prices 1.80% 0.90% 2.80% 3.50% Coal Prices -4.80% -0.50% 0.50% 1.20% * Fuel price assumptions are consistent with the Council’s fuel price and electricity price
forecast.



## FUEL PRICES

The future prices of natural gas, coal, and o il have an important effect on the Council’s power plan. As the Pacific Northwest’s electricity system has diversifie d beyond hydropower, it has become more connected to national and global en ergy markets. Fuel price assumptions affect demand, choice of fuel, and the cost of electricity generation. The effect on demand is primarily through retail natural ga s prices to consumers, but natural ga s prices may also affect electricity consumption because of its effect on cost. Oil and coal are not used extensively by end users in
the Pacific Northwest. Coal is , however, an important fuel for electricity generation; it affects the wholesale market price of el ectricity in some hours and the overall cost of electricity for utilities that rely on coal-fired generation.

The connection between fuel costs and electricit y planning has been strengthened by changes in energy regulation and the development of active trading markets for energy commodities. Less regulation and mature commodity markets have al so made the price of energy more volatile. The volatility of natural gas prices, in particular, is an important factor when considering the use of natural gas for electricity ge neration. Price volatility create s risks that the Council evaluates in developing a resource plan.

Because natural gas is the primary energy s ource affecting both the demand and supply of electricity, forecasts of natural gas prices receive far more deta iled attention than oil or coal prices. Fuel price forecasts st art with global, national, or regional energy commodity prices, depending on the fuel. Oil is a global commodity, natural gas is still primarily a North American commodity (although this could change as liquefied natural gas imports grow), and coal prices tend to be regional in nature. All of these co mmodities have experien ced periods of high and volatile prices since the Fifth Po wer Plan was issued in 2004. Na tural gas prices have collapsed since the summer of 2008. This reduction in pr ice is partly due to natural supply-and-demand responses to a period of high prices , but also to a great extent is a result of the current recessionChapter 2: Key Assump tions Sixth Power Plan

2-6 and financial crisis. 1 The Council’s forecast of natural gas prices assumes prices will rebound
from recent recession-induced lows.

Long-term fuel price trends are uncertain, as re flected in a wide range of assumptions. The Council’s power plan reflects thr ee distinct types of uncertainty in natura l gas prices: 1) uncertainty about long-term tre nds; 2) price excursions due to supply-and-demand imbalances that may occur for a number of years; and 3) short-term and seasonal volatility due to such factors as temperatures, storms , or storage levels. This se ction discusses only the first uncertainty. Shorter-term variat ions are addressed in the Council ’s portfolio model analysis as discussed in Chapter 9.

The high and low forecasts are intended to be extreme views of possibl e future prices from today’s context. The high case wellhead natu ral gas price increases to $9 by 2025 and increases to $10 by 2030. The Council’s forecasts assume th at rapid world economic growth will lead to higher energy prices, even though the short-term e ffects of a rapid price increase can adversely affect the economy. For the long-term trend anal ysis, the need to expand energy supplies, and its effect on prices, is considered the dominant fact or. The high natural gas scenario assumes rapid world economic growth. This scenario might be consistent with very high oil prices, high environmental concerns that limit use of coal, limited development of world liquefied natural gas (LNG) capacity, and slower improvements in drilling and exploration technology, combined with the high cost of other commodities and labor necessary for natural gas development. It is a
world where both alternative sources of en ergy and opportunities for reduced demand are
limited.

The low case assumes slow world economic growth that reduces the pressure on energy supplies. Wellhead natural gas prices in the low case fall to levels between $4 and $5 per million Btu; still double the prices during the 1990s. It is a future where world supplies of natural gas are made available through the aggressive developmen t of LNG capacity, favorable nonconventional supplies and the technologies to develop them, and low world oil prices that provide an alternative to natural gas use. The low case would also be consis tent with a scenario of rapid progress in renewable generating t echnologies, reducing demand for natu ral gas. In this case, the normal increases in natural gas use in response to lower prices would be limited by aggressive carbon-control policies. It is a world with substan tial progress in efficiency and renewable technologies, combined with more stable conditions in the Middle East and other oil- and natural gas-producing areas.

Many of the assumptions that lead to high or low fuel prices are independent of one another or have offsetting effects. Those conditions lead to the medium-fuel-price cases being considered more likely. Figures 2-2 through 2-4 illustrate the forecast ranges for natural gas, oil, and Powder River Basin (Wyoming) coal prices compar ed to historical prices. Tables 2-2 through 2- 4 show the forecast values for selected years. Appendix A provides a detailed description of the fuel price forecasts.

1 The fuel price forecast used for the pl an does not completely reflect the curre nt recession and the recent collapse in commodity prices. Therefore, the near-t erm prices through 2012 are likely high er than the most likely range. These
short-term differences are no t expected to affect the Council’s resource portfolio or planning results significantly, but will be modified for the final power plan.Chapter 2: Key Assump tions Sixth Power Plan

2-7 Most of the cases show fuel prices increasing from their recent depressed le vels in the early years of the forecast. Following this near-term recover y, longer-term trends in most of the cases show real fuel prices increasing gra dually. All prices, even in the lowest cases, remain well above prices experienced during the 1990s.

The fuel-price-forecast ranges are both higher an d broader than the Council’s Fifth Power Plan, reflecting greater uncertainty about long-term tr ends. The smooth lines for the price forecasts
should not be taken as an indica tion that future fuel prices wi ll be stable. Price cycles and volatility will continue. These variations, and the risks they impose, are introduced into the Council’s planning by the Resource Portfolio Model analysis.

Figure 2-2: U.S. Wellhead Natural Ga s Prices: History and Forecast Range

0 2 4 6 8 10 12

2 0 00 2002 20 0 4 2 0 0 6 2008 2010 20 1 2 2 0 14 2016 20 1 8 2 0 2 0 2 0 22 2024 20 2 6 2 0 2 8 20302006$ Per MMBtu History and Medium
Low
Medium Low Medium High High

Table 2-2: U.S. Wellhead Natural Gas Price Forecast Range (2006$ per MMBtu) Low Medium Low Medium Medium High High
200 8 7.47
2010 3.75 4.00 4.30 4.60 5.00
201 5 4.00 4.80 5.75 6.70 8.00
2020 4.25 5.40 6.25 7.25 8.50
202 5 4.35 5.80 7.00 7.85 9.00
2030 4.50 6.00 7.50 8.50 10.00
Growth Rates
2007 - 15 -7.51% -5.38% -3.22% -1.35% 0.86%
2007 - 30 -2.18% -0.95% 0.02% 0.56% 1.22%Chapter 2: Key Assump tions Sixth Power Plan

2-8 Figure 2-3: World Oil Prices : History and Forecast Range

0 20 40 60 80 100 120 14019701974197819821986199019941998200220062010201420182022202620302006$ Per Barrel History

Low

Medlo

Medium

Medhi

High

Table 2-3: World Oil Price Forecast Range (2006$ per Barrel) Low Medium Low Medium Medium High High
2007 65.29
2008 88.42
2010 55.00 60.00 65.00 70.00 75.00
2015 55.00 60.00 70.00 75.00 85.00
2020 52.00 62.00 72.00 80.00 92.00
2025 48.00 64.00 74.00 90.00 110.00
2030 45.00 65.00 80.00 95.00 120.00
Growth Rates
2007 - 1 5 -2.12% -1.05% 0.88% 1.75% 3.35%
2007 - 30 -1.60% -0.02% 0.89% 1.64% 2.68%Chapter 2: Key Assump tions Sixth Power Plan

2-9 Figure 2-4: Powder River Basin Minemo uth Coal Prices: History and Forecast

0.00 0.20 0.40 0.60 0.80 1.00 1.20 1.40

1 985 19 88 19 91 19 94 199 7 200 0 200 3 2 006 2 009 20 12 20 15 20 18 202 1 202 4 202 7 2 0302006$ Per Million Btu

History

Low

Medlo

Medium

Medhi

High

Table 2-4: Powder River Basin Minemout h Coal Price Forecasts (2006$ per MMBtu)

Low Medium Low Medium Medium High High
2007 - - 0.56 - -
2010 0.52 0.58 0.64 0.70 0.83 2015 0.51 0.58 0.66 0.73 0.88
2020 0.50 0.58 0.68 0.76 0.93 2025 0.48 0.57 0.69 0.79 0.99
2030 0.47 0.57 0.71 0.83 1.05 Growth Rates
2007-2015 -1.29% 0.32% 1.98% 3.33% 5.65%
2007-2030 -0.78% 0.05% 1.01% 1.67% 2.73%



## CARBON DIOXIDE PRICES

The risk of carbon-pricing polic ies is one of the key uncertain ties addressed in the Council’s Sixth Power Plan. Such policies have been pr oposed by the Western Climate Initiative and in proposed federal legislation. Whether, when, and at what level such policies might be implemented are all unknown at this time. Therefore, the plan treats these policies as a risk that should be considered in making electric resource choices made for the region.

The carbon risk scenario captures the carbon pric ing risk by modeling bo th the adoption of a policy and the amount of the carbon price, or penalt y, as random variables. The carbon price can be thought of as a carbon tax or the cost of a carbon-emission allowan ce under a cap-and-trade system. Once a carbon-pricing policy is implem ented, the price is assumed to fall between $0 and $100 per ton of carbon emissions. The modeling approach is described in Chapter 9. Figure
2-5 shows a decile chart of the range of resulting carbon prices. The average of the carbon prices begins at zero and increases to above $40 by mi dway through the forecast period ending at $47 per ton in 2030.Chapter 2: Key Assump tions Sixth Power Plan

2-10 Figure 2-5: Decile Chart of Carbon Pri ces Used in the Carbon Risk Analysis

0 20 40 60 80 100 120Sep-09Sep-10Sep-11Sep-12Sep-13Sep-14Sep-15Sep-16Sep-17Sep-18Sep-19Sep-20Sep-21Sep-22Sep-23Sep-24Sep-25Sep-26Sep-27Sep-28$2006/US ton CO2 100%

90%

80%

70%

60%

50%

40%

30%

20%

10%

0%

mean

Source: workbook "New CO2 Distribution 090425.xls", chart "Carbon Distribution"

The choice of the range of carbon pr ices to be considered was info rmed by research and review of the results of studies done by various organi zations on the likely cost of carbon allowances
that would result under various cap-and-trade policies. The Council commissioned a study by EcoSecurities Consulting Limited to review the literature on carbon-pricing studies and develop a range of likely prices under different policy scen arios. The range of estimates is very wide. Results depend on the study methodology, the ca rbon-reduction targets assumed, and the assumed scope and role of carbon-credit tradi ng. However, the bulk of the estimates fell between $10 and $100 per ton of CO 2 . Understanding that there is some chance that no carbon pricing policy will be agreed on, the Council used a range from $0 to $100 for its carbon-risk analysis.

In addition to this range of pri ces, a number of fixed-price leve ls and other price ranges were explored in the draft and final plan. The Council is not taking a position on carbon policy for the region by exploring various levels of carbon pric es. The analysis is intended to provide information on what would be required to meet existing goals in some states, and to provide information to the region on possible actions to mitigate the risks of unknown future carbonpricing policies. Chapters 10 and 11 discuss c limate change analysis and issues further.



## RENEWABLE PORTFOLIO STANDARD RESOURCE DEVELOPMENT

Renewable resource portfolio standards (RPS) ma ndating the development of certain types and amounts of resources have been adopted by ei ght states within th e Western Electricity Coordinating Council region: Arizona, Califor nia, Colorado, Montana, New Mexico, Nevada, Oregon, and Washington 2 . In addition, British Columbia has adopted an energy plan with

2 Utah’s Energy Resource and Carbon Emission Reduction Initiative adopted in 2008 has characteristics of a renewable portfolio standard, but mandates acquisition of qualifying resources only if cost-effective. BecauseChapter 2: Key Assump tions Sixth Power Plan

2-11 conservation and renewable-energy goals similar to an RPS. RPS laws are complex with great variation between states regard ing target amounts, qualifying re sources, resource “set-asides,” existing resource qualif ication, in-state credits, price caps, and other prov isions. State-by-state assumptions used for this forecast are described in Appendix D.

Mandatory development of low-variable-cost renewable resources ca n significantly affect wholesale power prices and the need for discretio nary resources. A forecast of the types of renewable resources that may be developed and the success in achie ving the targets is needed for the wholesale-power price forecast and the resource-portfolio analys is. The resulting estimate of need for new renewable energy to meet state RPS obligations is provided in Table 2-5.

Table 2-5: Estimated Committed and Foreca st Incremental RPS Generating Resource Requirements (MWa)

AZ BC CA (33%) CO MT NM NV OR WA

Committed 87 366 3954 454 65 111 273 465 520 Cumulative new (100% achievement of standards)
2010 32 0 425 0 0 0 21 0 0
2011 77 0 1,068 0 0 0 63 0 0
2012 115 0 1,774 0 19 0 137 0 0
2013 157 0 2,416 0 24 112 277 0 0
2014 196 17 2,863 280 31 147 339 0 218 2015 240 85 3,329 368 37 184 452 0 367
2016 313 136 3,401 450 37 214 463 0 511
2017 390 185 3,477 537 37 243 496 0 662
2018 471 239 3,551 626 37 273 508 0 812
2019 555 296 3,602 718 37 304 524 0 958
2020 642 351 3,674 813 37 335 537 0 953
2021 733 406 3,745 836 37 341 551 0 941
2022 826 462 3,816 860 37 346 566 478 939
2023 925 520 3,885 885 37 353 580 538 939
2024 1,027 579 3,954 910 37 359 595 599 941 2025 1,134 638 4,026 935 38 366 610 662 944
2026 1,163 698 4,099 961 38 372 626 670 950
2027 1,192 758 4,171 987 39 379 641 677 956
2028 1,223 819 4,244 1,014 39 385 657 685 965
2029 1,254 882 4,318 1,041 40 392 672 697 977 Total 1,341 1248 8,272 1,495 105 503 945 1,162 1,497

Table 2-5 shows the estimated qualifying energy needed to fully achieve current renewable portfolio standards. Because of price caps and ot her limiting factors, the forecast used for this plan assumes 95 percent achievement of standa rds. All energy from potentially qualifying existing capacity is assumed to be credited. Energy-efficiency measures, in states where credited, are assumed to be employed to the exte nt allowed. The remaining generating resource obligations (i.e., 95 percent of the new energy of Table 2-6) will be met by a mix of new resources, determined by state-specific resour ce eligibility criteria, new resource availability, resource cost, RPS policies governing use of out-o f-state resources, state- specific resource setasides and special credit and other factors. The resource mix in the near-term was assumed to resemble the mix of recent qualifying resource development. Over the planning period,

resource acquisitions based on cost-effectiveness are simulated by the capacity expansion logic of the AURORA xmp ® Electricity Market Model used for the wholesale power price forecast, it was not necessary to separately forecast renewable resource development for Utah.Chapter 2: Key Assump tions Sixth Power Plan

2-12 development is assumed to shift toward locally abundant, but relatively undeveloped resources such as solar thermal. Figure 2-6 illustrates the assumed incremental capacity additions needed to provide 95 percent of the cumulati ve energy requirements of Table 2-5.

To simplify the forecast, the C ouncil assumed that all new resource requirements would be met in-state, although it is clear that states such as California, with substantial need for qualifying RPS resources, will secure much of its RPS needs from out-of-state sources.

Figure 2-6: Forecast RPS capacity by resource type

0 5000 10000 15000 20000 25000 30000 35000 40000

2009 2014 2019 2024 2029Capacity (MW) Wind

Solar Thermal

Photovoltaics

Hydropower

Geothermal

Biomass



## WHOLESALE ELECTRICITY PRICES

The Council prepares and periodically updates a 20-year forecast of whol esale electric power prices, representing the future price of electrici ty traded on the wholesale, short-term (spot) market at the Mid-Columbia trading hub. Th e forecast establishes benchmark capacity and energy costs for conservation and generating resource assessments a nd serves as the equilibrium wholesale power prices for the Resource Portfolio Model. In addition, the forecast is used for
the ProCost model to assess the cost-effectiveness of conserva tion measures. The Council’s electricity price forecast is also used by other organizations for assessing resource costeffectiveness, developing resource plans, and for other purposes.

An overview of the development of the wholesale electricity price forecast and a summary of the results are provided in this se ction. A complete descripti on is provided in Appendix D.

The Council uses the AURORA xmp ® Electricity Market Model 3 to forecast wholesale power prices. Electricity prices are based on the variab le cost of the most expensive generating plant or

3 Supplied by EPIS, Inc. (www.epis.com)Chapter 2: Key Assump tions Sixth Power Plan

2-13 increment of load curtailment needed to meet load for each hour of the forecast period.
AURORA xmp ® , as configured by the Council, simulate s plant dispatch in each of 16 loadresource zones making up the Western Electric ity Coordinating Council (WECC) electric reliability area. The Northwest is defined as four of these zones: Western Oregon and Washington; Eastern Oregon and Washington, Nort hern Idaho and Western Montana; Southern Idaho; and Eastern Montana. The 16 zones are defined by transmission c onstraints and are each characterized by a forecast load (net of c onservation), existing gene rating units, scheduled project additions and retirements, fuel price fo recasts, load curtailment alternatives, and a portfolio of new-resource options. Transm ission interconnections between the zones are characterized by transfer capacity, losses, and wheeling costs. The demand within a loadresource zone may be served by native generation, imports from other zones, or (rarely) load
curtailment.

Three factors are expected to significantly influence the futu re wholesale power market: the future price of natural gas; the future cost of carbon dioxide (CO 2 ) production; and renewable resource development associated with state rene wable portfolio standard s (RPS). These factors will affect the variable cost of the hourly marginal resource and hence the wholesale power price.

Because natural gas is a relatively expensive fuel, natural gas-fired plants are often the marginal generating unit, and therefore de termine the wholesale price of electricity during most hours of the year. CO 2 allowance prices or taxes will raise the va riable cost of coal-fired units more than that of gas-fired units because of the gr eater carbon content of coal. Lower CO 2 costs will raise the variable cost of both gas and coal units, but not enough to push coal above gas to the margin. High CO 2 costs will move coal to the margin, above gas. In either case, the variable cost of the marginal unit will increase. As described earlier in this chapter, state renewable portfolio standards are expected to force the developmen t of large amounts of wind, solar, and other resources with low-variable costs, in excess of the growth in demand. This will force fossilfueled generators with lower variable costs to the margin, tending to reduce market prices.

A base case forecast, four sensitivity studies , and two bounding-scenario cases were run. The
base forecast assumes medium- case fuel prices and mean CO 2 prices. All forecast cases assume 95-percent achievement of state renewable portf olio standards, average hydropower conditions, medium load growth and achievement of all cost-effective conservation. The changing case assumptions are shown in Table 2-6.

Table 2-6: Price Forecast Case Changing Assumptions
Case Fuel Prices CO 2 Cost Base (mean CO 2 ) Medium Case Mean Low CO 2 Cost Medium Case 90% prob. of exceedance decile High CO 2 Cost Medium Case 10% prob. of exceedance decile
Medium-Low Natural Gas Medium-low NG Mean of RPM cases Medium-High Natural Gas Medium-high NG Mean of RPM cases Low Scenario Medium-low NG 90% prob. of exceedance decile High Scenario Medium-high NG 10% prob. of exceedance decile

For the base forecast, wholesale power prices at the Mid-Columbia trading hub are projected to increase from $30 per megawatt-hour in 2010 to $74 per megawatt-hour in 2030 (in real 2006 dollar values). For comparison, Mid-Columbia wholesale power prices averaged $56 per megawatt-hour in 2008 (in real 2006 dollars), dropping abruptly to $29 in 2009 with the collapseChapter 2: Key Assump tions Sixth Power Plan

2-14 of natural gas prices and reduction of demand due to the economic downturn. The levelized present value of the 2010-29 base case forecast is $56 per megawatt-hour.

Figure 2-7 illustrates recent and forecast whol esale power prices for the various cases. Comparing the shape of the power price forecasts with the mean CO 2 price forecast of Figure 2-5 clearly demonstrates the significant effect of CO 2 costs on prices. This is particularly evident in the high CO 2 and high-scenario cases. In these cases, prices rise rapidly early in the planning period as CO 2 prices increase, then st abilize and decline as CO 2 prices reach a steady-state of $100/ton of CO 2 and additional low-carbon resources are deployed.

Figure 2-7: Historical a nd Forecast Annual Average Mid-Columbia Wholesale Power
Prices

$0 $10 $20 $30 $40 $50 $60 $70 $80 $90 $100 $110 $120

2000 2005 2010 2015 2020 2025 20302006$/MWh Historical
Base (CO2 Mean)

Low CO2 Cost

Med-low NG
Med-high NG

B4 Low Scenario
B4 High Scenario High CO2 Cost

Northwest electricity prices tend to exhibit a seasonal pattern asso ciated with spring runoff in the
Columbia River Basin and lower loads as the weather moderates. The forecasts exhibit this pattern when viewed on a monthly average basis. Figure 2-8 shows the monthly average heavyload hours, all-hours, and light-loa d-hours prices for the base for ecast. A flattening of prices during high-runoff, lower-load seasons, becomi ng evident in the mid-term of the planning period, is likely attributable to the increasing proporti on of must-run resources with low variable

costs.

The levelized 2010-29 forecast values and values fo r selected years are shown in Table 2-7. The full monthly price series ar e provided in Appendix D.Chapter 2: Key Assump tions Sixth Power Plan

2-15 Figure 2-8: Monthly Aver age Base Case (Mean CO 2 ) Forecast of Mid-Columbia Wholesale
Power Prices

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

2008_01 2013_01 2018_01 2023_01 2028_012006$/MWh Heavy-load Hours

All Hours

Light-load Hours

Table 2-7: Forecast of Mid-Columbia Wholesale Power Prices (2006$/MWh)

Base LowCO 2 High CO 2 Med-Low NG Med-High NG Low Scenario High Scenario
2010 $30 $29 $29 $28 $31 $28 $31
2015 $54 $35 $86 $49 $59 $31 $90
2020 $63 $39 $99 $59 $69 $35 $104
2025 $70 $45 $98 $63 $74 $39 $95
2030 $74 $49 $91 $65 $79 $42 $93
Levelized (2010-29) $56 $38 $82 $51 $60 $34 $85
Growth Rates
2010-2029 4.4% 4.6% 2.6% 5.9% 4.3% 4.7% 2.0%

Forecast wholesale power prices have often been used to determine the avoided cost of new resources. Wholesale energy price forecasts, in general, must be used with caution in setting avoided costs because of capacity and risk consid erations. However, this price forecast in particular is not a suitable stand-al one measure of avoided resource costs. 4 This is because the Northwest, with the exception of Southern Id aho, enters the planning period with an energy

4 Market price adders representing the risk mitigation and capacity value of specific resource types can be calculated. The resulting sum of energy market prices, capacity credit and risk mitigation credit represents the avoided cost of the resource in question. This is the approach taken in this plan to establish the value of energy efficiency measures.Chapter 2: Key Assump tions Sixth Power Plan

2-16 surplus, and remains so throughout the planning pe riod because of the addition of resources to meet renewable-resource-portfolio requirement s. Because of this continuing surplus, no discretionary (non-RPS) resources are added by the model and therefore the resulting energy prices do not reflect the avoided cost of any new resource. The actual avoided-resource costs for the three Northwest states with renewable portf olio standards are the costs of the renewable resources added to meet RPS requirements a nd any capacity additions needed to supply balancing reserves (balancing-re serve requirements are not tracked in the model). Southern Idaho is the exception. Here, about 570 megawatts of simple-cycle gas turbines are added during the planning period to maintain capacity reserv es. Because this capacity only contributes incidental energy, even the en ergy price forecast for Southern Idaho does not represent the
avoided cost of needed resources.



## RETAIL ELECTRICITY PRICES

History

In the first half of the 1970s, consumers in th e Northwest experienced declining electricity prices. However, by mid-1970 and into the 1980s, the region experienced dramatic increases in the price of electricity, followed by an economic r ecession that hit the region particularly hard. In the latter half of the 1980s, electricity prices began a decade -long decline, in real (inflationadjusted) terms. But in late 2000, the region agai n experienced large increases in the price of energy, accompanied by a moderate recession. Si nce the sharp increase in 2000, electricity prices have stabilized, and even declined in inflation-adjusted pri ces. However, since 2006,
another round of more moderate price increases has begun to be re flected in increases in fuel prices and other commodities. Figure 2-9 illustrates this price history. 5

Figure 2-9: Average Retail Electri city Price by Sector (2006$/MWh)

- 10.00 20.00 30.00 40.00 50.00 60.00 70.00 80.00 90.00

1970

1 9 7 1
1 9 7 2 1973

1974

197

5
1 9 7 6 1977

1978

197

9
1 9 8 0
1 981

1982

1983

1 9 8 4
1 9 8 5 1986

1987

198

8
1 9 8 9
1 990

1991

199

2
1 9 9 3
1 994

1995

1996

1 9 9 7
1 9 9 8 1999

2000

2 0 0 1 2 0 0 2 2003

2004

200

5 2 0 0 6 2 0072006 dollars per MWH

Residential

Commercial

Industrial

5 Prices in Figure 2-7 are expressed in constant year 2006 dollars, as are many other tables and graphs throughout the plan.Chapter 2: Key Assump tions Sixth Power Plan

2-17 

## Forecast of Retail Electricity Prices

Typically, the price of el ectricity for investor-own ed utilities is determined through a regulatoryapproval process, with utilities bringing a rate case to their regulatory authority and seeking approval of future rates. Future rates depend on the cost of serving elec tricity to customers and the level of sales. The approve d rates should cover the variable and fixed-cost components of serving customers, plus a rate of return on invested capital. Fo r customer-owned utilities, rates are set by elected boards to recover the costs of se rving the electricity needs of their customers.

The methodology used for forecasting future electri city prices in the Sixth Power Plan is a simplified approach, where fixed and variable costs of the power system are estimated for each period and then divided by the volume of sales of electricity. The annual growth rate in average revenue requirement derived from the least-risk plan was applie d to sector-level electricity prices.



## Sector Retail Prices

The estimated price of electricity by sector and state is presente d in Tables 2-8 through 2-10. The annual real growth rate of elec tricity prices is expected to be about 1 percent per year for the 2010-2030 period. It should be noted that these for ecasts are at the state le vel, and within each state, individual electric utility rates may be higher or lower th an the figures presented here. Also, individual utilities may have significantly higher or lower rate increases than these average statewide figures would indicate.

Table 2-8: Price of Electricity for Residential Customers (2006$/MWh) Oregon Washington Idaho Montana
1985 74 60 68 74 2005 75 68 65 84
2010 89 79 74 96 2015 101 90 83 109
2020 109 97 90 117
2030 108 96 89 116 Annual Growth
1985-2000 -0.3% 0.0% -0.3% 0.1%
2000-2007 2.9% 3.9% 0.3% 2.7%
2010-2030 1.0% 1.0% 1.0% 1.0%Chapter 2: Key Assump tions Sixth Power Plan

2-18 Table 2-9: Price of Electricity for Commercial Customers (2006$/MWh) Oregon Washington Idaho Montana
1985 81 57 65 67 2005 67 65 56 77
2010 79 71 60 89 2015 89 80 67 101
2020 97 86 73 109
2030 93 83 70 104 Annual Growth
1985-2000 -1.3% -0.2% -1.2% -0.4%
2000-2007 3.2% 3.6% -0.3% 3.5%
2010-2030 1.0% 1.0% 1.0% 1.0%

Table 2-10: Price of Electricity for Industrial Customers (2006$/MWh) Oregon Washington Idaho Montana
1985 56 34 42 40 2005 50 44 40 50
2010 51 55 45 60 2015 58 62 51 67
2020 63 67 55 73
2030 60 64 53 70 Annual Growth
1985-2000 -1.3% 0.6% -0.6% 0.7%
2000-2007 4.8% 3.2% -0.1% 8.1%
2010-2030 1.0% 1.0% 1.0% 1.0%Sixth Northwest Conservation and Electric Power Plan 

# Chapter 3: Electricity Demand Forecast

Summary of Key Findings........................................................................................................ ...... 1
Introduction................................................................................................................... .................. 2
Historic Demand Growth......................................................................................................... ... 2
Sixth Power Plan Demand Forecast............................................................................................... . 4 Demand Forecast Range .......................................................................................................... ... 4
Sectoral Demand................................................................................................................ ......... 5
Load Forecast and Peak Load.................................................................................................... ..... 6 Peak Load...................................................................................................................... .............. 6 Load Forecast Range............................................................................................................ ....... 7 Alternative Load Forecast Concepts........................................................................................... 8 Portfolio Model Analysis of Non-DSI Load............................................................................. 10 Impact on Revenue Requirement.............................................................................................. 11 Demand From Plug-in Hybrid El ectric Vehicles (PHEV)........................................................ 12 Opportunities and Challenges............................................................................................... 14
Environmental Impacts ......................................................................................................... 1 5 Assessment of Needs - Utility Perspective ................................................................................... 16
Annual Needs................................................................................................................... ......... 16 Hourly Needs ................................................................................................................... ......... 18
Annual Load Forecast Tables .................................................................................................... ... 21



## SUMMARY OF KEY FINDINGS

The Pacific Northwest consumed 19,000 averag e megawatts or 166 million megawatt-hours of electricity in 2007. That demand is expected to grow to 25,000 average megawatts by 2030 in
the Council’s medium forecast. Between 2009 and 2030, load is expected to increase by a total of 7,000 average megawatts, growing on averag e by about 335 average megawatts, or 1.4 percent, per year. 1 This forecast has been influenced by e xpected higher electricity prices that reflect a rapid rise in fuel prices and emerging carbon-emissi on penalties. For example, residential consumer retail electricity prices are expected to increase by 1.0 percent per year in addition to general inflation. If achieved, cost-e ffective efficiency improvements identified in the Sixth Power Plan will help to meet a substa ntial portion of this pr ojected demand growth.

The electricity demand increase is driven primarily by significant growth in two areas: home
electronics and elder-care fac ilities. Demand for home electr onics--a new component to the
Council’s residential sector--is expected to double in the next 20 years. In the commercial sector, the elder-care segment is increasing as th e population ages. While th e industrial sector is growing at a relatively slow pace, custom data centers (Google, etc.) are a relatively new end-use that has been seeing significant growth as well.

The Northwest has always been a winter-peakin g power system. However, due to growing summer load, mostly because of the increased use of air conditioning, the difference between winter- and summer-peak load is expected to shrink over time. Assuming normal weather conditions, winter-peak demand in the Sixth Power Plan is proj ected to grow from about 34,000 megawatts in 2010 to around 43,000 megawatts by 2030, an average annual growth rate of 1 percent. Summer-peak demand is forecast to grow from 29,000 megawatts in 2010 to 40,000

1 Demand for electricity, measured at consumer location, is projected to grow by about 6,000 average megawatts, growing on average by about 300 megawatts or 1.4 percent per year.Chapter 3: Electricity Dema nd Forecast Sixth Power Plan

3-2 megawatts by 2030, an annual growth rate of 1.7 pe rcent. By the end of the planning period, the gap between summer-peak load and winter-peak load has narrowed.

The projected growth of demand is comparable to the actual growth rate experienced during the
1990s. When new cost-effective conservation is subtracted, the need fo r additional generation will be quite small compared to past experien ce. However, summer supply needs will likely increase as summer-peak demand co ntinues to grow. In addition, the growing share of variable wind generation may change the types of generati on needed to meet demand. There is likely to be an increased need for resources that can provide reliable capacity to meet high load conditions and that can operate flexibly to accommoda te variable, but non-CO2 emitting, wind energy.



## INTRODUCTION

The 2001 energy crisis in the West refocused th e region on long-term demand forecasting. There has been a renewed interest and concern about ge nerating capacity and flexibility as well. To deal with these issues, the Council replaced its end-use forecasting models with a new end-use forecasting and policy analysis tool and, workin g with Bonneville, adapted it to the regional power system and the Council’s planning requir ements. The new demand forecasting system is based on the Energy 2020 model and generates forecas ts for electricity, natural gas, and other
fuel.

The Energy 2020 model is an integrated end-us e forecasting model. The Council will use the demand module of Energy 2020 to forecast annual en ergy and peak loads for electricity as well
as other fuels. The model has been used extens ively by several utilities, and within the region
the Bonneville Power Administration uses a version of it.

Three electricity demand forecasts were develope d in the Sixth Power Plan. Each scenario corresponds to an underlying set of economic driver s, discussed in Chapter 2 and Appendix B. The high and low ranges of the load forecasts are not explicitly used in the development of the Power Plan, but rather are used as loose gui delines for the regional portfolio model when creating the 750 alternative load forecasts. These demand scenario s reflect an estimate of the impact of the current recession.



## Historic Demand Growth

It has been 26 years since the Council’s first Po wer Plan in 1983. In th e decade prior to the Northwest Power Act, regional demand was growi ng at 4.1 percent per yearand the non-directservice industry (DSI) lo ad was growing at an annual rate of 5.2 percent. Back in 1970, regional demand was about 11,000 average megawatts. In the decade between 1970 and 1980, it grew by about 4,700 average megawatts. During the 1980s, demand growth slowed significantly, falling to about 1.5 percent per year and load increa sed by about 2,300 average megawatts. In the 1990s, another 2,000 average megawatts were added to regional demand, making growth in the last decade of the 20th century only about 1.1 percent per year. The energy crisis of 2000-2001 increased electricity prices dramatically. As a result, regional demand decreased by 3,700 average megawatts between 2000 and 2001, and elimin ated much of the growth since 1980. The
bulk of this decline was in the region’s aluminum industry and ot her energy-intensive industries. Since 2002, however, regional demand has begun to recover, growing at an annual rate of 2.5 percent. This growth has been driven by increa ses in commercial and residential sector demand. Nevertheless, demand remains well below levels of the late 1990s. Table 3-1 and Figure 3-1 illustrate regional electricity demand from 1970-2007.Chapter 3: Electricity Dema nd Forecast Sixth Power Plan

3-3 Table 3-1: Historical Growth Rate of Regional Electricity Sales 2

Annual Growth Total Sales Non DSI
1970-1979 4.1% 5.2%
1980-1989 1.5% 1.7%
1990-1999 1.1% 1.5%
2000-2007 -0.8% 0.5%
2002-2007 2.5% 2.2%

Figure 3-1: Total and Non-DSI Re gional Electricity Sales (MWa)

The dramatic decrease in demand after the Po wer Act was not due to a slowdown in economic growth in the region. The region added more population and more j obs between 1980 and 2000
than it did between 1960 and 1980. The decrease was the result of a shift in the regional economy as the number of energy-in tensive industries de clined, largely becaus e of the dramatic increase in electricity prices th at followed the region’s over-inve stment in nuclear generation in
the 1970s and increased investment in conservation. As shown in Table 3-2, electricity intensity in terms of use per-capita increased between 1980 and 1990, but has been declining since 1990.

Table 3-2: Changing Electricity-Use Intensity of the Regional Economy (Non-DSI Sales Per Capita Adjusted for the weather)

Year Electricity Use per Capita (MWa / Thousand Person)
1985 1.50
1990 1.57
2000 1.52
2007 1.45

The upswing in demand since 2002 has been mainly due to growth in residential and commercial sector sales. By the end of 2007, the residential sector had ad ded about 888 average megawatts and the commercial sector had added 285 average megawatts, whereas the industrial sector saw a reduction of 337 average megawatts. The industria l sector represented 6,300 average megawatts of demand in 2000, but by 2002 the demand from the industrial sector was reduced to 3,300 average megawatts. The bulk of the drop in de mand was due to the closure of aluminum smelting plants, which accounted for nearly 40 pe rcent of industrial elec tricity use. The demand from this industrial group dropped from 2,543 megawatts in 2000 to about 410 megawatts in 2002. Large users in a few industr ial sectors such as pulp and pa per, food processing, chemicals, primary metals other than aluminum, and lumb er and wood products dominate the remainder of
the industrial sector’s electricit y use. Many of these sectors ha ve declined or are experiencing

2 2007 is the last year for reliable data on regional sa les. Reliable 2008 data are not available at this time.Chapter 3: Electricity Dema nd Forecast Sixth Power Plan

3-4 slow growth. These traditional, resource-based industries are becoming less important to regional electricity demand, while new industrie s, such as semiconductor manufacturing, are growing faster.



## SIXTH POWER PLAN DEMAND FORECAST

Demand is forecast to grow from about 19,000 average megawatts in 2007 to 25,000 average megawatts by 2030 in the medium-case forecast. The average annual rate of growth in this forecast is about 1.2 percent. This level of growth does not take in to account reductions in energy from new conservation reso urces. To the extent conserva tion is used to meet demand growth, the forecast will decrease.

Assuming normal weather conditions, the winter-peak load for power is proj ected to grow from about 34,000 megawatts in 2010 to around 43,000 megawatts by 2030 at an average annual growth rate of 1 percent. Summer-peak load is projected to grow from 29,000 megawatts in 2010 to 40,000 megawatts by 2030, an annual gr owth rate of 1.6 percent.

The medium-case forecast means that the regi on’s electricity needs would grow by about 6,000 average megawatts by 2030, absent any conserva tion, an average annual increase of 267 average megawatts. Most of the growth is from incr eased electricity use by the residential and commercial sectors, with slower growth in the in dustrial sector, especially for energy-intensive industries. Higher electricity and natural gas prices have fu ndamentally shifted the energy intensity of industries in the region. As a re sult of the 2000-01 energy crisis and the mild recession of 2002, the region lost about 3,500 averag e megawatts of industrial demand, which it has not regained. The region is projecte d to surpass the 2000 level of demand by 2013. However, the depth of the 2008-09 rece ssion may prolong this recovery.



## Demand Forecast Range

Uncertainty about economic and demographic vari ables, along with uncertainty about fuel prices, adds to uncertainty about demand. To ev aluate the impact of these economic and fuelprice uncertainties in the Sixth Power Plan, two alternative demand forecasts were produced. The Sixth Power Plan’s low to high range is ba sed on Global Insight’s October 2009 range of
national forecasts. To forecast demand under each scenario, the appropriate economic and fuel projections were used. Table 2-1, presented in Chapter 2, shows a range of values for key economic assumptions used for each scenario. The resulting range in the demand forecast is shown in Table 3-3 and Figure 3-2.

Two alternative scenarios were developed for the Sixth Power Pl an. The most likely range of demand growth (between the low and high forecast s) is between 0.8 and 1.5 percent per year. The low scenario reflects a prolonged recovery fr om the recession, and the high scenario reflects a more robust recovery and future growth.Chapter 3: Electricity Dema nd Forecast Sixth Power Plan

3-5 Table 3-3: Sixth Northwest Power Plan Electricity Demand Forecast Range (MWa) 3

Actual

2007 2010 2020 2030 Growth Rate 2010-2020 Growth Rate 2020- 2030 Growth Rate 2010-2030

Low 19,140 18,860 20,463 22,010 0.8% 0.7% 0.8%

Medium 19,140 19,292 21,820 25,275 1.2% 1.5% 1.4% High 19,140 19,591 22,651 27,761 1.5% 2.1% 1.8%

Figure 3-2: Historical Sixth Northwes t Power Plan Sales Forecast (MWa)

- 5,000 10,000 15,000 20,000 25,000 30,000

1986 1988 199 0

19

92 1994 1996 1998 2000 200 2

2004 2006 2008 2010 2012 2014 2016 2018 2020 2022 2 024 2026 2028 2030MWA

Price-Effect High Case Low Case 1985-2007 Actual 2008-2030 Forecast
with Normal Weather



## Sectoral Demand

The Sixth Power Plan forecasts demand to grow at an average annual rate of 1.4 percent in the 2010 through 2030 period. The residential sector is expected to grow at 1.4 percent per year, which, on average, translates to about 125 mega watts each year. Incr eased growth in the
residential sector reflects a substantial increas e in demand for home electronics, categorized as information, communication, and entertainment (ICE) and the increased use of air conditioning.

Table 3-4 shows the actual 2007 demand for electricity and the forecast for selected years, as well as the corresponding annual growth rates. These demand forecasts do not include any new
conservation initiatives.

3 Sales figures are electricity use by consumers and exclude transmission and distribution losses.Chapter 3: Electricity Dema nd Forecast Sixth Power Plan

3-6 Table 3-4: Medium-Case Sector Fo recast of Annual Energy Demand (MWa)

Actual

2007 2010 2020 2030 Growth Rate 2010-2020 Growth Rate 2020-2030 Growth Rate 2010-2030
Residential 7,424 7,499 8,335 9,987 1. 06% 1.82% 1.44%
Commercial 6,129 6,705 8,214 9,170 2. 05% 1.11% 1.58%
Industrial Non-DSI 3,904 3,724 3,715 4,360 -0 .03% 1.62% 0.79%
DSI* 764 693 772 772 1.09% 0.00% 0.54% Irrigation 848 599 696 873 1.52% 2.29% 1.90% Transportation 71 72 87 113 1.91% 2.62% 2.27%

Total 19,140 19,292 21,820 25,275 1.24% 1.48% 1.36%

* Long-term DSI forecast developed by RPM, project s a lower DSI load than the values reflected
here.

Commercial sector electricity consumption is forecast to grow by 1.6 percent per year between 2010 and 2030. During this period, commercial sect or demand is expected to increase from 6,700 average megawatts to 9,200 average megawatts . This increase is higher than the 1.2 percent per year that was forecast in the Fift h Power Plan (May 2005). The Sixth Power Plan cases have been adjusted upward to reflect the fact that there has been a tendency to underforecast commercial demand. The forecast for 2025 is about 1,700 average megawatts higher
than the 2025 medium forecast in the Fifth Power Plan. On averag e, this sector adds about 110 average megawatts per year.

Industrial electricity demand is di fficult to forecast with much c onfidence. Unlike the residential and commercial sectors, where energy use is predominately for bu ildings, and therefore reasonably uniform and easily related to househol d growth and employment , industrial electricity use is extremely varied. Also, i ndustrial electricity use tends to be concentrated in relatively few, very large users instead of spread among many relativel y uniform users.

Industrial (non-direct -service industries) consumption is fore cast to grow at 0.8 percent annually. Electricity consumption in this sector is fo recast to grow from 3,900 average megawatts in 2007 to 4,400 in 2030. One segment of th e industrial sector that has e xperienced signifi cant growth is that of custom data centers. Although these businesses do not manufactur e a tangible product, they are typically classified as industrial customers because of the amount of electricity they use.
The Council’s estimates show that there are curr ently about 300 average megawatts of connected
load for these businesses. Demand from this sector is forecast to increase by about 7 percent per year. However, considering exis ting opportunities to improve the energy efficiency of custom data centers, it was assumed that demand from these centers will grow about 3 percent per year.

In the Sixth Power Plan, DSI consumption was assumed to be around 600-700 average megawatts for the forecast period. Although the portion of Alcoa's Wenatchee aluminum
smelter that is served from non- BPA sources is not technically a DSI (it is not served by BPA), that load is included in the DSI categor y for convenience in the Sixth Power Plan.



## LOAD FORECAST AND PEAK LOAD

Peak Load

The Council’s new long-term demand forecasting system forecasts annual sales, as well as monthly energy and peak load. The Council often refers to electricity sales to consumers as demand, following the Northwest Power Act’s defin ition. The difference between sales and load is transmission and distribution losses on power line s. Regional peak load is determined fromChapter 3: Electricity Dema nd Forecast Sixth Power Plan

3-7 the end-use level for each sector. The region al peak load for power , which has typically occurred in winter, is expected to grow from about 34,000 megawatts in 2010 to around 43,000 megawatts by 2030 at an average annual growth ra te of 1.1 percent. Assuming normal historical temperatures, the region is expected to rema in a winter-peaking system, although summer peaks are expected to grow faster than winter peak s, significantly narrowing the gap between summerpeak load and winter-peak load.

The forecast for regional peak load assume s normal weather conditions. There are no assumptions regarding temperature changes incorporated in the Sixt h Power Plan’s load forecast
at this time. Sensitivities will be conducted to he lp assess the potential effects of climate change on electricity use (See Appendix L). Figure 3-3 shows estimated actual peak load for 1985- 2007, as well as the forecasts for 2008-2030. Note th at load growth looks very steep due to the graph’s smaller scale.

Figure 3-3: Historical and Forecast Regional Peak Load (MW)

- 5,000 10,000 15,000 20,000 25,000 30,000 35,000 40,000 45,000

19

8

6

1

988 1990 1

99

2

1

99

4

1 996 1998 2000 2002 2004 2

00

6 2008 2

0 10

2

01

2

20

14

2

016 2018 2020 2022 2

02

4 2

026 2028 2

03

0MW

Winter Peak Summer Peak 1985-2007 Regional Peak
with actual weather conditions 2 008-2030 Regional Peak

w ith normal weather conditions



## Load Forecast Range

Figure 3-5 shows forecast winter and summer peak load under the three alternative cases. Assuming the high-growth scenario , regional summer-peak load is e xpected to grow from about 28,000 megawatts in 2007 to about 43,000 mega watts by 2030. Between 2010 and 2030, the growth rate in summer-peak load is 1.9 percent per year. The growth rate of winter-peak load in the high case is lower than the growth in average annual energy demand. Assuming normal weather, the region is forecast to remain a winter-peaking system. However, the difference between winter and summer peak loads shrinks over time.Chapter 3: Electricity Dema nd Forecast Sixth Power Plan

3-8 Table 3-5: Total Summer and Wint er Peak Load Forecast Range (MW)

Actual

2007 2010 2020 2030 Growth Rate 2010-2020 Growth Rate 2020-2030 Growth Rate 2010-2030
Low - Winter 33,908 33,572 35,412 36,949 0. 5% 0.4% 0.5%
Low - Summer 28,084 28,517 32,027 35,559 1. 2% 1.1% 1.1%
Medium - Winter 33,908 34,184 37,977 42,814 1. 1% 1.2% 1.1%
Medium - Summer 28,084 29,211 33,800 39,865 1. 5% 1.7% 1.6% High - Winter 33,908 34,611 39,397 46,788 1. 3% 1.7% 1.5% High - Summer 28,084 29,706 34,923 43,360 1.6% 2.2% 1.9%

In the low case, summer-peak load is expected to grow from 28,000 megawatts in 2007 to 35,000 megawatts in 2030. Winter-peak load grows from 34,000 in 2007 to 37,000 in 2030. Other patterns between summer a nd winter peaks are similar to th e other cases. Winter peaks grow more slowly than average ener gy load, and summer peaks grow faster.



## Alternative Load Forecast Concepts

Three different but related load forecasts are produced for use in the Council’s resource planning process. The first of these forecasts is called a “price-effect” forecast, which is the forecast that has been presented up to this point. The price-e ffect forecast is the official demand forecast required by the Northwest Power Act.

The price-effect forecast reflects customers’ choic es in response to electricity and fuel prices and technology costs, without any new conservation initiatives. This forecast does not include new
conservation resources. Howe ver, expected savings from existing and approved codes and standards are incorporated in the price-effect forecast, consequently re ducing the forecast and removing the potential from the ne w conservation supply curves.

To eliminate double-counting the conservation po tential, the load-for ecasting model produces two other long-term forecasts that are required for estimating conservation potential and running the resource portfolio model.
1. Frozen-efficiency forecast . A “frozen-efficiency” forecast is when load is calculated
based on fixed or frozen efficien cy levels as of the base year of the plan. This forecast attempts to eliminate the doubl e-counting of conservation savi ngs. The frozen technicalefficiency levels form the conservation s upply model’s starting point. In the frozenefficiency forecast, the fuel efficiency choice is held constant at the base-year level and not changed over time, except where there is a known increase due to codes or standards.
2. Sales forecast . A “sales” 4 forecast represents the actual e xpected sales of electricity after
all cost-effective conserva tion has been achieved. It incorp orates the effects of electricity prices and the cost-effective conservation r esources that are sele cted by the regional portfolio model. The sales forecast captures both price effects and take-back effects (due to increased usage as efficien cy of usage increases).

The difference between the price-e ffect and frozen-efficiency load forecasts is relatively small. The frozen-efficiency forecast typically is higher than the price-effect forecast; in the Sixth Power Plan the two forecasts differ by about 400 average megawatts by 2030. Figures 3-4 through 3-6 show these three forecasts for energy and for summer and winter capacity in the

4 The “sales” forecast, as well as price-ef fect and frozen efficiency, can be measur ed at a consumer or generator site (which would include transmission and distribution losses). Demand is measured at the customer site, and load is measured at the generator site.Chapter 3: Electricity Dema nd Forecast Sixth Power Plan

3-9 Sixth Power Plan. Conservation reso urce program savings incorporated 5 in the sales forecast reduce 2030 average annual load by about 5,900 megawatts and reduces summer peak load by about 6,000 megawatts, or roughly by 15 percent. Winter peak loads are reduced by about 11,000 megawatts or about 24 percent.

Figure 3-4: Average A nnual Load Forecasts (MWa)

- 5,000 10,000 15,000 20,000 25,000 30,000 35,000

2009 2 010 2 011 2 012 2 013 2 014 2 015 2 016 2 01

7

2 01

8

2 01

9

2 02

0

2 0 21 2 0 22 2 0 23 2 0 24 2025 2026 2027 2 028 2 029 2 030MWa

Price-Effect Frozen-Efficiency Sales Forecast

Figure 3-5: July Peak Load Forecasts (MW)

0 5,000 10,000 15,000 20,000 25,000 30,000 35,000 40,000 45,000

2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 202 0

2021 2022 2023 2024 202 5

2026 2027 2 028 2029 2030MW

Price-Effect Frozen Efficiency Sales Forecast

5 Anticipated annual impacts of conservation programs, by sector and end-use, are netted out of the frozenefficiency loads for that year, sector, and end-use.Chapter 3: Electricity Dema nd Forecast Sixth Power Plan

3-10 Figure 3-6: January Pe ak Load Forecasts (MW)

0 5,000 10,000 15,000 20,000 25,000 30,000 35,000 40,000 45,000

2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030MW

Price-Effect Frozen Efficiency Sales Forecast



## Portfolio Model Analysis of Non-DSI Load

While the Council uses three types of long-term load forecasts, the monthly frozen-efficiency load forecast is the primary forecast used in the regional portfolio model (RPM) for developing alternative future load-growth paths. The RPM takes the frozen-efficiency load forecast and
introduces short-term excursions that simulate such events as business and energy commodity price cycles and load variations that could be caused by weather ev ents. In any given period, the RPM may deviate from the long-term load foreca st; however, on average th e loads created by the RPM are very close to the frozen-efficiency lo ad forecasts. The following table shows a comparison between the frozen-efficiency load forecast and the RPM-ge nerated loads. The graph shows a representative range of load fo recasts developed. The RPM generates 750 different future load-growth paths; to graphically represent all th ese futures would not possible. Here, the averages of the highest 15 percent and lowest 15 percent of the 750 load paths, as well as the average of all the 750 growth paths, are compared with the frozen-efficiency forecast. It should be noted the loads presented in this graph are for non-DSI loads. A more robust discussion of the RPM is presented in Chapter 9 and Appendix J.Chapter 3: Electricity Dema nd Forecast Sixth Power Plan

3-11 Figure 3-7: Load Forecasts (MWa)

- 5,000 10,000 15,000 20,000 25,000 30,000 35,000

201 0

2011 2012 2013 2014 2015 2016 201 7

2018 2019 202 0

2021 2022 2023 2024 2025 2026 2027 2028 2029MWa

Average of 750 Futures Frozen-Efficiency Bottom 15% Top 15%



## Impact on Revenue Requirement

What is the impact of the plan’s resource re commendations on customers’ electricity costs and how do predicted costs compar e to historic trends?

Customers’ bills are expected to decrease by 0. 2 percent to 0.7 percent per year depending on treatment of CO2 costs. If the CO2 penalty is not included in th e revenue requirement, customers’ electricity bills are e xpected to decline at an average annual rate of 0.7 percent. If CO2 costs are included, customers’ electricity bills are expected to decline at an average annual rate of 0.2 percent. It shoul d be noted that over time residen tial customer bills and the revenue requirement change at different rates, due to an increasing number of households. The average revenue requirement grows at an av erage annual rate of 0.5 percent, 6 and the number of households grows at a rate of 1.2 percent, resulting in bills decrea sing at 0.7 percent per year.

To compare the future trend in costs with the hi storic trend, we need to create comparable numbers by removing the effects of inflation. The dollars of revenue collected by electric utilities for each year between 1990 and 2008 we re converted to 2006 dollars. The future projected revenue requirement under the carbon risk scenario was co mpared to historic levels. The historic and future revenue requiremen t was indexed to 2008 by setting 2008 revenues to 100. Analysis shows that duri ng the 1990-to-2008 period the reve nue requirement increased at an average annual rate of 1. 6 percent. In the 2010-to- 2030 period, under the carbon-risk scenario, the revenue collected from customers is projected to increase at an average annual rate of 0.5 percent to 1.0 percent per year, depending on the incidence of the CO2 tax. More detail

6 The calculation of future revenue requirements includes an assumption that current fixed costs of resources, transmission, and distribution systems remain fixed in real dollars. Implicit in this assumption is that the cost of new transmission and distribution infrastructure expansion is offset by the depreciation of existing infrastructure assets. Eastern Montana wind, however, is assumed to require additi onal transmission investment and that cost is explicitly
added to the cost of the Montana wind resource.Chapter 3: Electricity Dema nd Forecast Sixth Power Plan

3-12 regarding the impact of the plan on average revenue and customer bills can be found in Appendix O.

Figure 3-8: Indexed Revenue Requirement

- 20 40 60 80 100 120 140

1 99

0

1 992

1 994 1996

1 998 2 0 00 2 002 2 00

4 2 006 2 00

8 2 010 2 012 2014 2 016 2 0 18 2 020 2 02

2 2024 2 026 2 028 Least Risk Plan With CO2 Least Risk Plan Without CO2 2008=100 $2006 dollars



## Demand From Plug-in Hybrid Electric Vehicles (PHEV)

Over 70 percent of automakers 7 are introducing plug-in hybrid electric vehicles (PHEV). Between 2010 and 2030 we estimate that more than13 million new passenger and light vehicles will be purchased in the No rthwest, of which 600,000 to 3. 5 million could be PHEV.

To better understand the potenti al impact of PHEV on the system load, a limited “what-if” sensitivity study was conducted. 8 The Council assumed a range of penetration of these cars into the market, with the re sult that regional electricity use increases by between 100 and 550 average megawatts.

The estimated effects on electricity bills and rate s were small. The impact on rates to a large extent depends on when the PHEV is recharged. In the Council’s analys is, it was assumed that 95 percent of PHEV recharge would occur at night or on weekends, during system off-peak hours. To encourage and ensure off-peak rech arge would require regul atory and technological changes. Technological change in the form of smart grid and uni form recharge protocols would
enable the owners of PHEV to know the optimum recharge period. Regulatory rates would need to provide incentives for off-peak charging.

The forecast of new light vehicles in the four No rthwest states indicat es that between 2010 and
2030 about 13 million new vehicles will come on to the roads. Some of these vehicles would replace existing vehicles and so me would meet new transporta tion requirements of a growing population. The PHEV share of this market would depend on a number of factors such as gasoline prices, tax on CO2 emissions, and the price and reliability of PHEV. In the sensitivity analysis, it was assumed that all these factor s translate into a market share factor. Three

7 By market-share, from E-source pr esentation on “Building the plug-in Vehicle Infustructure” Nov 2009.

8 This sensitivity study was not included in the base case (price effect) analysis for the plan.Chapter 3: Electricity Dema nd Forecast Sixth Power Plan

3-13 different long-term market-share factors were assumed. Case 1 assumes 10-percent market share, while cases 2 and 3 assume 28 pe rcent and 40 percent, respectively.

The following figures show the year-by-year market-share assumptions as well as annual and off-peak energy requirements for PHEV. It was assumed that market acceptance of PHEV will be small in the first five years of their introduction. By the 15 th year, the assumption is that market acceptance will level off at 10-40 percent. Figure 3-9 shows the assumed annual newvehicle market-penetration rates fo r PHEV. We also have assume d that the efficiency of the
PHEV and conventional fossil-fuel vehicles w ould improve over time. Figures 3-10 and 3-11 show the annual demand for electricity for PHEV . PHEV are expected to add between 100-550 average megawatts to regional load and about twice as much to the off-peak demand. A detailed discussion of PHEV analysis is presen ted in Appendix C of the power plan.

Figure 3-9: Assumed New Car Market Share for PHEV

0% 5% 10% 15% 20% 25% 30% 35% 40% 45%

2010 2 0 1 1 2 0 1 2 2 0 1 3 2 0 1 4 2 0 1 5 2 0 1 6 2017 2018 2019 2020 2021 2 0 2 2 2 0 2 3 2024 2025 20 2 6 2027 2028 2029 2 0 3 0Percent of New cars

Case 1 Case 2 Case 3Chapter 3: Electricity Dema nd Forecast Sixth Power Plan

3-14 Figure 3-10: Projected Load fr om Plug-in Hybrid Vehicles

- 200 400 600

2 0 1 0 2011 2 0 12 20 1 3 20 1 4 2015 2 0 1 6 2017 2 0 18 2 0 1 9 2020 2021 2 0 2 2 2023 2 0 24 2 0 2 5 2026 2 0 2

7 2 0 2 8 2029 2030MWa

Case 1 Case 2 Case 3

Figure 3-11: Project Off-peak Load from Plug-in Hybrid Vehicles

- 200 400 600 800 1,000 1,200

2 010 20 11 2012 2013 20 14 201 5 2016 2 017 20 18 2019 2020 20 21 202 2 2023 2 024 20 25 2026 2027 20 28 202 9 2030MW

Case 1 Case 2 Case 3



### Opportunities and Challenges
The projected levels of PHEV penetration represent both oppor tunities and challenges for the power system in the Northwest. If fully s ubscribed, by 2030, the PHEV fleet potentially could store the equivalent of between 2 and 10 percent of the energy and between 3 and 20 percent of the eight-hour sustained peaki ng capacity of the hydropower sy stem in the Northwest.

However, integration of potentially millions of PHEVs into the power grid will require building an intelligent bi-directional telecommunication infustructure that w ould optimize recharge
schedules based on consumers’ drivi ng habits and power utilities’ ne eds. What is needed is anChapter 3: Electricity Dema nd Forecast Sixth Power Plan

3-15 integration of three sectors- transportation, info rmation, and electric power. To make possible the communication between local utilities, millio ns of dispersed vehicles, and thousands of recharge stations, common na tional communication standards along with local utilities’ incentivized rates and a seamless recharge infrastruc ture are necessary. The utilities will need to provide incentives to PHEV drivers to subscrib e to smart charging programs, where the utility could manage the timing and pace of the recharge.



### Environmental Impacts
The impact of PHEV on the emissions from electricity generation depends on the timing of recharge and future mix of generation. In th e regional portfolio model, by 2030 the difference in CO2 emissions from the power system was 0.8 million me tric tons higher 9 due to PHEV loads. But the increase in CO2 emissions from power plants is more than offset by the decrease in emissions by vehicles. The US Department of Ener gy estimates that in the four states of Oregon, Washington, Idaho, and Montana, tail-pipe emi ssions in 2007 were about 90 million metric tons. The Council’s estimates show that, depending on market acceptance of PHEV and response from conventional-fuel vehicles, 10 by 2030 tail-pipe emissions could be lower by 2 to 9 million metric

tons.

Figure 3-12: Potential Reduction in Tail-pi pe CO2 due to Plug-in Hybrid Vehicles

- 1,000,000 2,000,000 3,000,000 4,000,000 5,000,000 6,000,000 7,000,000 8,000,000 9,000,000 10,000,000

2 010 2011 201 2

2 013 2 014 2015 2 0

1 6

2 017 2 018 2 0

1 9

2 0 2 0

2 0 2

1

202 2

2 0 2 3

2 0 2 4

2025 202 6

2 0 2

7

2 028 2029 203 0Metric Tons

Case 1 Case 2 Case 3

Meeting the energy requirement of PHEV may not re quire new resources. . Council analysis shows that if the plan’s con servation targets are met, by 2030 the off-peak demand for energy could be reduced by about 3,800 megawatts. Th is amount of off-peak demand reduction would be sufficient to power an all-PHEV new vehicles fleet in the region.

9 37.8 million metric tons compared to 37 million in the least-risk scenario.

10 This assumes that as a result of national standards, high er fuel prices and availability of PHEV, conventional fuel vehicles would improve their fuel efficiency from 21.7 miles per gallon in 2010 to 35 miles per gallon by 2030.Chapter 3: Electricity Dema nd Forecast Sixth Power Plan

3-16 

## ASSESSMENT OF NEEDS - UTILITY PERSPECTIVE

Regional utilities have consistently used the annu al average load/resource balance as a quick and simple metric to get an indication of their reso urce needs. For the region, the load/resource balance reported in PNUCC’s No rthwest Regional Fore cast (NRF) provides an aggregate look at utility-resource needs. That calcul ation assumes firm loads and resources, 11 which include critical-water hydropower generati on but no market resources. A general conclusion that can be made from this metric is that when the averag e annual load is greater than the firm supply,
additional resources lik ely are needed.

However, this utility-perspective metric is ve ry limited and requires assessment. The Council and utilities must use more sophist icated analyses, which take othe r uncertainties into account, in order to develop a more comprehensive needs assessment and, more importantly, a robust resource-acquisition strategy (more commonly referred to as an inte grated resource plan). The Council’s methodologies for assessing the region’s needs and for developing a resource strategy are described in Chapter 9 (Developing a Res ource Strategy) and in Chapter 10 (Recommended Resource Strategy), respectively.

The Council’s assessment of power supply adeq uacy, developed by the Resource Adequacy Forum, uses a more sophisticated methodology than simply comparing firm loads and resources. Adopted by the Council in 2008, it uses probabilistic tools to assess the lik elihood of potential problems given firm, non-firm, and market resources. A mo re detailed description and a summary of results are provided in Chapte r 14 (Resource Adequacy Standards).

Yet, in spite of the limitations of the simple firm-load/resource-balance metric for assessing resource needs, this perspective is beneficial in that it is read ily available to all utilities and provides a starting poi nt for further discussion. Also, by reconfiguring Council assessments to fit this perspective, results can be compared with other utility-published re ports. The following section illustrates the Council’s assumptions fo r loads and resources po rtrayed in a utility perspective.



## Annual Needs

As a starting point for assessing regional resource needs based on a utility perspective, it is necessary to identify long-term load uncertainty and existing firm -resource capability. Existing resources include those that are owned or operate d by regional utilities to serve regional loads, regardless of their physical locati on. The generating capability of existing resources is adjusted
for maintenance and for the likelihoo d of forced outages. It is also adjusted to reflect utility operating assumptions. For example, a utility may own a 100-megawatt capacity simple-cycle combustion turbine, which it intends to use for h ourly peaking needs only. Because of the way in which the utility expects to operate this resource, it may only use 5 percent (or 5 average megawatts) to count toward the annual average fi rm-resource generating capability. The existing resource capability shown in the following charts has been adjusted for this effect.

The range of uncertainty in long-term loads (through the year 2030), was derived from the regional portfolio model, which takes into accoun t a wide variation in potential future economic growth. The high end of the load uncertai nty range represents the average load for

11 Firm loads are net of firm exports and imports. Firm resources consist of firm non -hydropower and critical-water hydropower resources.Chapter 3: Electricity Dema nd Forecast Sixth Power Plan

3-17 approximately the highest 15 percent 12 of the load paths from the model. The low end of the range represents the average load for approximately the lowest 15 percent of the load paths from the model. This load range includes the net e ffect of firm contractua l imports and exports.

The following graphs compare existing firm-res ource generating capability (as defined above) with the high and low range for future loads. The floating blocks in Figure 3-13 represent the range of uncertainty in load growth through the en d of the study horizon. In 2029, for example, annual regional firm load can range from a lo w of about 23,000 average megawatts to a high of about 31,000 average megawatts.

Based on a utility perspective, as depicted in Figure 3-13, exis ting firm resource capability is only sufficient to satisfy regional needs through 2 012. However, this does not mean that our power supply is inadequate. What it does mean is that counting only fi rm resources (in a way defined by utilities) and cri tical hydropower generation, the power supply cannot serve the anticipated firm load. This gap can be filled in a number of ways. Utilities could choose to build or acquire additional firm resources, purchase from the electricity market, operate their existing
resources at levels above their planning dispatch levels, or any combination of the three. The optimum strategy must be derived from a compre hensive integrated reso urce-planning process, which takes many other f actors into account.

The data presented in Figure 3-13 is consistent with information provided in PNUCC’s NRF. Unfortunately, it provides a relatively narrow view of potential regional needs because it excludes independent power-produc er resources and potential ac cess to resources outside the region. In addition, it offers little guidance in terms of de veloping a cost-effective resourceacquisition strategy. It does, however, indicate that a potential need for new resources exists and that further analysis is required.

Figure 3-13: Utility-Perspectiv e Energy Needs Assessment (MWa)

- 5,000 10,000 15,000 20,000 25,000 30,000 35,000

2010 2011 2012 201 3

2014 2 015 2016 2 017 2018 2019 2020 2021 2022 202 3

2024 202 5

2026 2 027 2028 2029

Existing Firm Resources Load Range

12 More precisely, the high end range of load uncertainty fo r each year is the average of the yearly loads for the top 100 simulations (out of 750 total) sorted by load in the last year of the study (2030).Chapter 3: Electricity Dema nd Forecast Sixth Power Plan

3-18 

## Hourly Needs

Although not used as often in the past, capac ity load/resource balances are becoming more important for assessing the need for new res ources. The combination of rapidly growing summer loads and decreasing summer hydroelectric ca pability is pushing the region to consider more carefully its peaking needs in summer months. Traditionally, capacity load/resource balances have been measured as surplus reserve ma rgins, in units of percent. To calculate a capacity reserve margin, surplus firm-generating capability for the peak-load hour of the day is divided by the load during that hour. This surplus capacity must be sufficient to cover operatingand planning-reserve requirements, fluctuations in load due to te mperature, and the potential loss of a generating resource. In regions that are dom inated by thermal resources, the desired reserve margin typically is in the range of 15 to 17 percent.

The Northwest, however, is a hydroelectric-dominated system that has limited storage capability. The aggregate storage capacity of all reservoirs is only about 30 percent of the annual average
runoff volume in the Columbia River. Because of this storage limitation and other factors, the Northwest power system cannot sustain its sing le-hour generating capabi lity over long periods. A more appropriate measure of hourly capability is the generation that the system can sustain over a three-day period, which approximates the duration for cold snaps or heat waves in the Northwest. This sustained-peak capability then can be compared to the sustained-peak load. However, to date, no standard has been estab lished for a utility-pe rspective (firm only) sustained-peak reserve-margin requirement. 13

Using the same methodology as fo r the energy-needs assessment above, the utility-perspective January and July sustained-peak capacity needs assessments are illustrated in Figures 3-14 and 3- 15. These results cannot be compared dire ctly to PNUCC’s Northwest Regional Forecast because it currently does not repo rt capacity data. For January , existing firm resources fall below the high end of the sustained-peak load range by the year 2028; for July, resources fall short of the high end of the load range by the year 2026. However, the loads shown in these figures do not include any reserve -margin requirements. Adding t hose requirements to the load range will result in an earlier need for resource acquisition. But, as discussed above, utilityperspective, sustained-peak reserv e requirements are not clear.

Figure 3-14: Utility-Perspective Ja nuary Capacity Needs Assessment (MW)

13 The Resource Adequacy Forum has developed minimum sustained-peak reserve-margin thresholds using a lossof-load probability analysis (as defined in the Council-adop ted adequacy standard). But these thresholds were developed under the assumption that some non-firm resources would be available for dispatch during emergency periods. Because of that, the Forum’s thresholds cannot be compared to reserve margins calculated using firm resources only.Chapter 3: Electricity Dema nd Forecast Sixth Power Plan

3-19 - 5,000 10,000 15,000 20,000 25,000 30,000 35,000 40,000 45,000 50,000

2010 2011 2012 201 3

2014 201 5

2016 2 017 2018 2 019 2020 2021 2022 2023 2024 2025 2026 202 7

2028 202 9

Existing Firm Capacity SPP Peak Load Range

Figure 3-15: Utility Perspective Ju ly Capacity Needs Assessment (MW)

- 5,000 10,000 15,000 20,000 25,000 30,000 35,000 40,000 45,000

2010 2011 2012 2013 201 4

2015 2 016 2017 2018 2 019 2020 2021 2022 2023 2024 2025 2026 2027 202 8

2029

Existing Firm Capacity SPP Peak Load Range

An alternative way to display the utility-persp ective hourly needs assessment is to graph the sustained-peak reserve margins calculated from data shown in Figures 3- 14 and 3-15. Figures 3- 16 and 3-17 show the resulting sustained-peak reserve margin ranges for January and July, respectively, using existing firm resources only. If the minimum required reserve margins for January and July were known, these figures woul d indicate the years in which new resources would be needed. Using 17 percent 14 as a surrogate for the utility-perspective sustained-peak reserve-margin threshold, the need for new re sources occurs in 2016 fo r January and in 2015 for July (when the reserve margins drop below 17 perc ent). However, these results do not provide an accurate assessment of hourly needs.

14 California utilities historically have used a 15-to-17-pe rcent reserve-margin requirement for long-term resource planning. However, that requirement is only appropri ate for a thermal-based power system, which focuses on single-hour needs as opposed to sustained-peak needs.Chapter 3: Electricity Dema nd Forecast Sixth Power Plan

3-20 Figure 3-16: Utility-Perspective January Reserve Margins (%)

-10%

0% 10% 20% 30% 40% 50% 2010 2011 2012 2013 2014 201 5

201 6

201 7

201 8

201 9

2020 2021 2022 2023 2024 2025 2026 2027 2028 2029

Max RM

Min RM

Figure 3-17: Utility Perspective July Reserve Margins (%)

-20% -10%

0% 10% 20% 30% 40% 50% 2010 2011 201 2

201 3

2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 202 6

2 027 2 028 2 029

Max RM

Min RMChapter 3: Electricity Dema nd Forecast Sixth Power Plan

3-21 

## ANNUAL LOAD FORECAST TABLES

Table 3-5: Annual Load under Various Scenarios (MWa)

Low Case Price-Effect (Medium Case) High Case Sales Forecast (Loads Net of Conservation)
1986 18,272

1987 18,751

1988 19,842

1989 20,681

1990 20,922

1991 21,258

1992 20,807

1993 21,097

1994 20,875

1995 21,140

1996 21,836

1997 21,591

1998 21,902

1999 22,382

2000 22,443

2001 19,321

2002 19,835

2003 20,010

2004 20,204

2005 20,582

2006 21,054

2007 21,575

2008 22,239

2009 21,367 21,369 21,371 21,369

2010 21,258 21,745 22,081 21,557

2011 21,580 22,194 22,626 21,800

2012 21,903 22,566 22,982 21,950

2013 21,985 22,774 23,188 21,919

2014 22,181 23,116 23,574 22,009

2015 22,286 23,346 23,875 21,978

2016 22,508 23,675 24,299 22,036

2017 22,745 24,015 24,743 22,084

2018 22,933 24,292 25,091 22,032

2019 23,053 24,499 25,364 21,900

2020 23,063 24,593 25,530 21,652

2021 23,232 24,890 25,932 21,610

2022 23,433 25,246 26,422 21,631

2023 23,631 25,618 26,963 21,673

2024 23,802 25,990 27,512 21,708

2025 23,977 26,374 28,080 21,755

2026 24,135 26,753 28,650 21,803

2027 24,288 27,153 29,255 21,948

2028 24,458 27,582 29,915 22,172

2029 24,627 28,028 30,593 22,422

2030 24,806 28,488 31,291 22,815
2010-2030 0.77% 1.36% 1.76% 0.28%%Chapter 3: Electricity Dema nd Forecast Sixth Power Plan

3-22 Table 3-6: Regional Winter and Su mmer Peak Load Forecast Range (MW)

Regional Winter Peak (MW) Regional Summer Peak (MW)

Low Case Priceeffect High Case Sales Forecast (Net of Conservation) Low Case Priceeffect High Case Sales Forecast (Net of Conservation)

1986 27,515 22,069

1987 28,241 22,651

1988 29,885 23,970

1989 31,150 24,985

1990 31,515 25,277

1991 32,021 25,683

1992 31,340 25,137

1993 31,775 25,486

1994 31,440 25,217

1995 31,840 25,538

1996 36,118 26,644

1997 33,292 25,287

1998 35,971 28,198

1999 30,753 27,156

2000 31,910 27,636

2001 30,215 22,697

2002 28,883 26,002

2003 29,395 27,391

2004 32,936 26,752

2005 32,654 26,961

2006 32,951 28,275

2007 33,908 28,084

2008 34,811 29,702

2009 33,700 33,704 33,707 33,704 28,591 28,591 28,592 28,591

2010 33,572 34,184 34,611 33,823 28,517 29,211 29,706 29,039

2011 33,948 34,774 35,347 34,029 29,074 29,912 30,513 29,548

2012 34,280 35,248 35,841 34,092 29,649 30,530 31,080 29,959

2013 34,376 35,559 36,185 33,970 29,865 30,896 31,419 30,106

2014 34,571 35,995 36,699 33,953 30,249 31,457 32,022 30,438

2015 34,678 36,323 37,132 33,793 30,476 31,825 32,473 30,575

2016 34,898 36,741 37,681 33,700 30,875 32,336 33,107 30,849

2017 35,130 37,167 38,249 33,577 31,299 32,862 33,763 31,122

2018 35,313 37,525 38,718 33,322 31,660 33,295 34,274 31,267

2019 35,420 37,807 39,109 32,970 31,922 33,629 34,676 31,307

2020 35,412 37,977 39,397 32,479 32,027 33,800 34,923 31,193

2021 35,557 38,350 39,926 32,191 32,359 34,262 35,513 31,378

2022 35,734 38,783 40,550 31,948 32,734 34,805 36,224 31,667

2023 35,907 39,237 41,235 31,731 33,102 35,371 37,008 32,004

2024 36,056 39,698 41,937 31,501 33,431 35,934 37,799 32,341

2025 36,211 40,177 42,666 31,365 33,764 36,509 38,615 32,647

2026 36,352 40,655 43,405 31,244 34,106 37,101 39,432 32,950

2027 36,487 41,159 44,187 31,293 34,441 37,740 40,320 33,355

2028 36,637 41,693 45,033 31,466 34,808 38,423 41,305 33,855

2029 36,786 42,245 45,898 31,668 35,174 39,133 42,317 34,392

2030 36,949 42,814 46,788 32,202 35,559 39,865 43,360 35,043
2010- 2030 0.5% 1.1% 1.5% -0.25% 1.1% 1.6% 1.9% 0.94%Sixth Northwest Conservation and Electric Power Plan 

# Chapter 4: Conservation Supply Assumptions

Summary of Key Findings........................................................................................................ ...... 1 Recent Changes Since the Fifth Power Plan................................................................................... 2
Federal Standards.............................................................................................................. .......... 3 New Sources of Potential Savings .............................................................................................. 4 Estimating the Cost of Conservation ............................................................................................ .. 4 Resource Potential Estimates by Sector......................................................................................... . 6 Residential Sector ............................................................................................................. .......... 6 Agriculture Sector............................................................................................................. .......... 8
Commercial Sector.............................................................................................................. ........ 9
Industrial Sector.............................................................................................................. .......... 11 Utility Distribution Systems ................................................................................................... .. 12
Consumer Electronics ........................................................................................................... .... 13 Estimating the Availability of Conservation Over Time .............................................................. 14
The Pace of Historic Cons ervation Achievements ................................................................... 15 Estimating the Annual Availability of Future Conservation Development.............................. 17 Testing Annual Pace Constraint s for the Portfolio Model........................................................ 19 Council Methodology ............................................................................................................ ....... 20 Implications for the State of Wa shington’s I-937 Requirements.............................................. 22



## SUMMARY OF KEY FINDINGS

The Council defines conservation as improved energy efficiency. This means that less electricity is used to provide the same leve l of services. Conservation resources are measures that ensure that new and existing residential buildings, hous ehold appliances, new and existing commercial buildings, commercial-sector appl iances, commercial infrastructure such as street lighting and sewage treatment, and industrial a nd irrigation processes are energy-e fficient. These efficiencies reduce operating costs and ultimately decrease the need to build new power plants. Conservation
also includes measures to reduce electrical lo sses in the region's generation, transmission, and distribution system.

The Council identified nearly 7,000 average mega watts of technically achievable conservation potential in the medium demand forecast by the end of the forecast period. Most of this potential, about 6,000 average megawatts, is available at a levelized (net) life-cycle cost of up to $200 per megawatt-hour (2006 dollars). Sources of achievable potential savings are about 50 percent higher than in the Fifth Power Plan. 1 The assessment is higher for two principle reasons. First, the Council identified new sources of savi ngs in areas not addressed in the Fifth Power Plan: consumer electronics, outdoor lighting, and the utility distribution system. Second, savings potential has increased significantly in th e residential sector as a result of technology improvements and in the industrial sector as a result of a more de tailed conservation assessment.

1 For purposes of comparison, the Council’s Fifth Power Plan estimated that the ac hievable conservation was approximately 3,900 average megawatts at cost up to $120 per megawatt-hour. This plan’s estimate of achievable potential is 5,860 average megawatts at an equivalent levelized life-cycle cost.Chapter 4: Conservation Suppl y Assumptions Sixth Power Plan

4-2 Not all of the nearly 7,000 average megawatts identified are cost-effective to develop. The Council uses its portfolio model to identify the amount of conservation th at can be economically developed. The results presented in this chapter serve as an input to th e resource portfolio model (RPM) which will test varying amounts of conser vation against other resource options across a wide range of future conditions. The results of the RPM analysis are presented in Chapter 10.

The achievable savings at cost up to $200 pe r average megawatt break down as follows:

• About 2,600 average megawatts of conserva tion are technically achievable in the residential buildings and appliances sect or. Most of the savings come from improvements in water-heating efficiency and heating, ventilating, and air-conditioning efficiency.

• Over 800 average megawatts of potential sa vings are estimated in the fast-growing consumer electronics sector. These savings co me from more efficient televisions, set top boxes, desktop computers, and monitors prim arily in homes but also in businesses.

• Approximately 100 average megawatts of cons ervation are available in the agriculture sector through irrigation sy stem efficiency improvements, improved water management practices, and dairy milk processing.

• Over 1,400 average megawatts of potential sa vings are available from the commercial sector. Nearly two-thirds of commercial savings are in lighting systems. New technologies like light-emitting diodes and impr oved lighting fixtures and controls offer added potential savings in bot h outdoor and indoor lighting.

• Potential savings in the i ndustrial sector are estimate d to be nearly 800 average megawatts by the end of the forecast pe riod. The industrial assessment found that effective business management practices c ould significantly incr ease savings from equipment and system optimization measures.

• Finally, potential savings from improved effi ciency in utility di stribution systems are estimated to be about 400 average megawatts by the end of the forecast period.

While there are a number of barriers to achievi ng these savings, the Council believes these challenges can be met.



## RECENT CHANGES SINCE THE FIFTH POWER PLAN

The Fifth Power Plan recommende d that the region develop at least 700 average megawatts of conservation savings from 2005 through the e nd of 2009. Based on surveys conducted by the Council’s Regional Technical Foru m, regional conservation progr ams already achieved savings of 700 average megawatts by the end of 2008 and ar e likely to achieve a total savings of over 900 average megawatts by the end of 2009.Chapter 4: Conservation Suppl y Assumptions Sixth Power Plan

4-3 

## Federal Standards

Since the Fifth Power Plan was adopted, C ongress enacted the 2007 En ergy Independence and Security Act (EISA) and the Department of Ener gy has promulgated several new standards. The EISA legislation revised severa l existing federal efficiency standards and established new standards as well. The most significant EISA st andard requires “general service lighting” (40 - 100 watt lamps) to be at least 30 percent more efficient beginning in 2012, and 60 percent more efficient beginning in 2020. The Fifth Power Plan estimated that converting standard incandescent bulbs to compact fl uorescent light bulbs (CFL) coul d save the region 625 average megawatts by 2025. The EISA standard does not cover all incandescen t bulbs. For example, bulbs over 100 watts, parabolic reflector lamps, candelabra, and 3-way light bulbs are exempt. These standards phase in beginning with a 30 pe rcent improvement in efficiency for 100 watt general service lamps in 2012 and end with a 60 pe rcent improvement in efficiency for all 60 to 100 watt general service lamps in 2020. The Counc il estimates that approximately 285 average megawatts of regional conservation potential remain s to be captured in re sidential lighting prior to 2020 and from lamps not covered by those st andards. Savings from lamps covered by the initial phase of EISA should count toward the region’s conservation target in 2010 and 2011.

EISA also sets minimum standards for certain commercial lighting products that were incorporated into the conserva tion assessment and load forecast. In addition, new efficiency standards were developed and adopted since 2004 for a suite of residential and commercial appliances regulated by federal la w or state standards. Baseline assumptions for energy use of new appliances and equipment have been updated in the new conservation assessment to reflect these improved standards. Table 4-1 shows a su mmary of all the federal standards that have changed since the adoption of the Fifth Power Plan and the effective date s of these new and/or
revised standards.Chapter 4: Conservation Suppl y Assumptions Sixth Power Plan

4-4 Table 4-1: New or Revised Federal Sta ndards Incorporated in Sixth Power Plan Conservation Assessment Baseline Assumptions Product Regulated Effective Date Battery Chargers and External Power Supplies July 1, 2008 Clothes Washers (Residential) January 1, 2007 Clothes Washers (Commercial) January 1, 2011 Consumer dehumidifier products October 1, 2012 Dishwashers (Residential) January 1, 2010 Ice Makers (Commercial) January 1, 2010 Motors December 17, 2010 Distribution Transformers (Low Voltage) January 1, 2007 Distribution Transformers (Medium-voltage, dry-type and Liquid-immersed distribution transformers) January 1, 2010

Packaged Air Conditioners and Heat Pumps (Commercial - ≥ 65,000 Btu/h) January 1, 2010

Refrigerators and Freezers (Commercial) January 1, 2010 Single-Package Vertical Air Conditioners and Heat Pumps January 1, 2010 Walk-In Coolers and Walk-In Freezers (Commercial) January 1, 2009 Ceiling Fan Light Kits January 1, 2007 Compact Fluorescent Lamps (Efficacy and Rated Life) January 1, 2006 Exit Signs January 1, 2006 Fluorescent Lamp Ballasts Beginning October 1, 2009 and phasing in through July 2010 Incandescent General-Service Lamps Beginning January 1, 2012 and phasing in through 2014 Incandescent Reflector Lamps June 1, 2008 Metal Halide Lamp Fixtures January 1, 2009
Torchieres January 1, 2006



## New Sources of Po tential Savings

Additional savings were identified from utility distribution systems. Distribution system savings, including voltage management and system optimization, add about 400 average megawatts of conservation poten tial not included in the Fift h Power Plan assessment.

A more in-depth analysis of th e industrial sector more than doubled the conservation potential
identified in the Fifth Power Plan.

Along with these major adjustments, the conserva tion assessment incorpor ates new conservation opportunities brought about by technological advances . For example, recent advances in solidstate lighting--light-emitting diodes (LED) and organic light-emitting diodes (OLED)--appear to offer significant opportunities for savings in tele visions and some lightin g applications. The arrival in the U.S. market of ductless heat pum ps for space heating also provides new savings opportunities.



## ESTIMATING THE COST OF CONSERVATION

The Council determines the tota l resource cost of energy savings from all measures that are technically feasible. This pro cess requires comparing all the cost s of a measure wi th all of its benefits, regardless of who pays those costs or who receives the benefits. In the case of efficient clothes washers, the cost includes the difference (if any) in retail price be tween the more efficientChapter 4: Conservation Suppl y Assumptions Sixth Power Plan

4-5 Energy Star model and a standard efficiency mode l, plus any utility progr am administrative and marketing costs. On the other side of the e quation, benefits include the energy (kilowatt-hour) and capacity (kilowatt) savings , water and wastewater trea tment savings, and savings on detergent costs. 2 While not all of these costs and benef its are paid by or accrue to the region’s power system, they are included in the eval uation because ultimately, it is the region’s consumers who pay the costs a nd receive the benefits.

Once the net cost (levelized over the life of the c onservation resource) of each of the conservation technologies or practi ces is determined, the technol ogies are ranked by cost in two supply curves that depict the amount of conservati on resource available in the region. These net
levelized costs of conservation are calculated the same way that le velized costs of new generating resources are calculated so they can be compared.

One supply curve represents all of the retrofit or non- lost opportunity re sources. The other represents all the lost-oppor tunity conservation resources. 3 The Council divides conservation resources into these two categories because their patterns of deployment are different. Non-lost opportunity conservation resources can be deployed at any time. Lost-opportunity resources are only available during specific peri ods; for example, when new bu ildings are built with improved insulation. Savings from most app liances are available only as appl iance stock turns over. If the savings from these lost-opportuni ty resources are not acquired within this limited window of opportunity, they are treated as lost and no l onger available at that time or cost.

Figure 4-1 shows the Sixth Power Plan’s estimate of the amount of conservation available by sector and levelized life-cycle cost. The Council identified about 6,000 average megawatts of achievable conservation potential in the medium demand forecast by the end of the forecast period at a levelized life-cycle cost of up to $200 per megawatt-hour (2006 dollars). New sources of potential savings result in about 50 pe rcent more achievable po tential compared to the Fifth Power Plan. Slightly less than half of the potential is from lost- opportunity measures.

2 Energy-efficient clothes washers use less water and require less detergent.

3 Lost-opportunity resources can only be technically or economically captured during a limited window of opportunity, such as when a building is built or an industrial process is upgraded.Chapter 4: Conservation Suppl y Assumptions Sixth Power Plan

4-6 Figure 4-1: Achievable Conservation by 2029 by Sector and Levelized Cost

0 1000 2000 3000 4000 5000 6000 7000 8000

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Levelized Cost (2006$/MWh)Achievable Potential by 2029 (MWa) Residential Consumer Electronics

Commercial Industrial Agriculture Utility Distribution



## RESOURCE POTENTIAL ESTIMATES BY SECTOR

Residential Sector

In the Fifth Power Plan, the Council estimated that approximately 1,600 average megawatts of conservation potential was technically available in the residential sector from improvements in lighting, appliances, and water-heating technologies at a levelized cost of less than $120 per megawatt-hour (2006 dollars). The Sixth Power Plan ’s estimate for these same end-uses places the remaining technically achievable conservatio n at nearly 2,600 average megawatts at an equivalent cost.

The largest decrease (475 average megawatts) in residential-sector potential came from the new federal efficiency standards for lighting. Figur e 4-2 shows the residential resource potential by major category and cost. The figure shows that the largest remaining savings come from improvements in water-heating efficiency and heating, ventilating, and air conditioning (HVAC) efficiency. These increases in residential sector potential stem from greater availability of heat pump water heaters, the introduction of ductless heat pumps to the U.S. market, and cost reductions for high-effi ciency heat pumps.

Since the adoption of the Council’s Fifth Power Pl an, the Northwest Energy Efficiency Alliance (NEEA), with the support of the Bonneville Powe r Administration and other regional utilities, and in cooperation with the Energy Trust of Oregon, launched a regionwide marketChapter 4: Conservation Suppl y Assumptions Sixth Power Plan

4-7 transformation program to encourag e the installation of split-system heat pumps. These systems, referred to as “ductless heat pumps,” do not use forced-air ducts to perform their heating and cooling function. Instead, they di stribute the hot or cold refriger ant created by an outside unit to inside units through refrigerant lin es. The advantage of these syst ems is that they can be more easily installed in homes with electric resist ance zonal heating systems (baseboard, ceiling radiant, or wall fan units). Wh ile these systems are used throughout Northern Europe and all across Asia, Australia, and New Zealand, they have only recently been promoted in the U.S. If the savings and cost estimates adopted by the Regional Technical Foru m are confirmed through
NEEA’s market transformation venture, this technology has th e potential to reduce regional space-heating use by approximately 200 average megawatts at a cost of less than $60 per megawatt-hour.

The Council’s Fifth Power Plan estimated that regional electric wate r-heating use could be reduced by approximately 200 average megawatts through the installation of heat pump water heaters commercially available at the time of the plan’s adoption. 4 However, since there were no major water heater manufacturers producing heat pump water heaters, the Council’s estimate of potential savings from these heaters fell short.

Figure 4-2: Residential-Sect or Achievable Conservation by Sector and Levelized Cost

- 500 1,000 1,500 2,000 2,500 3,000 3,500

< 0 <10 <20 <30 <40 <50 <60 <70 <80 <90 <100 <110 <120 <130 <140 <150 <160 <170 <180 <190 <200 >200

Levelized Cost (2006$/MWh)Achievable Potential by 2029(average megawatts) Direct Application Renewable (DHW/PV) HVAC Building Shell Lighting Appliances Water Heating

Three major U.S. water heater manufacturers began producing heat pump water heaters in 2009. Consequently, the Council raised its estimate of the maximum pene tration of these systems from 25 percent of single family and manufactured home s with electric water heat to 50 percent. Nevertheless, since these are new pr oducts, it is likely that their initial market penetration rates will be modest. The Council assumes that by the end of 2014 the market share of these heaters

4 A heat pump water heater uses a compre ssor that circulates hot refrigerant thro ugh a heat exchanger in a water tank
to heat water rather than el ectric resistance elements.Chapter 4: Conservation Suppl y Assumptions Sixth Power Plan

4-8 will be just over 1 percent. However, by 2030 heat pump water heater s could reduce regional electric water heating use by over 490 average me gawatts at a cost less than $30 per megawatthour.

The third largest increase in residential sectorpotential came from the lower costs of highefficiency heat pumps for space heating. When the Fifth Power Plan was adopted, the minimum federal standards for heat pumps and air conditioners had just gone into effect. As a result, there was little price competition among products that exceeded these new standards. Based on program data obtained from the Energy Trust of Oregon, high performance heat pump costs have come down. Moreover, it now appears that heat pumps with a minimum performance level of 17 percent above the federal standards are more cost competitive than those that only exceed the federal standards by 10 percent. At a levelized life-cycle cost of less than $80 per megawatthour, there are almost 375 average megawatts of savings available from converting new and existing single family and manufactured homes with electric forced-air furnaces to highperformance heat pumps. At less than $80 per megawatt-hour, the potential savings from upgrading new and existing homes with higher efficiency heat pumps are 100 average megawatts.


## Agriculture Sector

The Fifth Power Plan identified approximately 100 average megawatts of conservation potential available in the region through effi ciency improvements in irrigation system hardware. Since the Fifth Power Plan, almost 685,000 acres have b een added as land irri gated by pressurized sprinkler systems. However, due to improvements in system effi ciency, such as the conversion to low-pressure delivery systems and improve d water management, total estimated regional electricity use for irrigation decreased from 655 average megawatts to 645 average megawatts.

After accounting for these changes, the Council estimates that approximately 75 average megawatts of conservation remains available thro ugh hardware efficiency improvements such as pump efficiency, leak reducti on, conversion to lower pressure applications, and better sprinkler/nozzle management practices at costs significantly below $100 per megawatt-hour.

Along with improving irrigation syst em hardware, better water mana gement practices could also reduce the energy consumed in irrigation. Desp ite some of the measure’s limitations due to state-specific water laws, over 15 average megawa tts of conservation potential are available in the region through scientific irri gation water scheduling. More pot ential exists if mechanisms can be found to ensure that irrigation water savi ngs on one farm are not consumed by additional irrigation on farms with junior water rights.

Non-irrigation “on farm” electricit y use in the remainder of the ag riculture sector is dominated by dairy milk production. According to the De partment of Agriculture, the region produced approximately 20 billion pounds of milk in 2007. Idaho and Washington rank among the top 10 states in milk production and Oregon ranks 18. The Council estimates that 2007 electricity use for dairy milk production was approximately 55 av erage megawatts. Many of the dairies in the region, and particularly in Idaho, were establis hed and/or enlarged w ithin the last decade. Consequently, many already have energy-efficient lighting, pumps, and milk cooling equipment. Nevertheless, the Council estimates that approx imately 10 average megawatts of conservation potential is available through improvements such as variable-speed driv es on milking machineChapter 4: Conservation Suppl y Assumptions Sixth Power Plan

4-9 vacuum pumps, the use of flat-plate heat exchan gers for pre-cooling milk prior to refrigeration, and improved lighting. A summary of the technically achievable c onservation in the agriculture sector is shown in Figure 4-3

Figure 4-3: Agriculture Sector Ac hievable Conservation by 2030 (MWa) by Sector and Levelized Cost

- 20 40 60 80 100 120

< 0 <10 <20 < 3 0

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Irrigation Water Management Irrigation Hardware Dairy



## Commercial Sector

Over 250 commercial-sector conservation measures were analyzed to develop the conservation potential for the Sixth Power Plan. The assessm ent includes lighting, hea ting, ventilation, and air conditioning (HVAC), and envelope measures in 19 separate bu ilding types such as offices, retail stores, warehouses, and schools. The assess ment covers several cl asses of electricityintensive process equipment used in buildings su ch as refrigerators, computers, and ventilation
hoods. The assessment also covers infrastructure activities such as stre et and highway lighting, municipal sewage treatment, a nd municipal water supply.

The aggregate Sixth Power Plan conservation potentia l is similar to what was identified in the Fifth Power Plan, over 1,400 average megawatts. However, the allocations by measure and end
use are different. For the Sixth Power Plan, there is more conser vation potential in lighting and less in HVAC. Updated analysis has reduced conservation potential for several key HVAC measures that appeared in the Fifth Power Pla n. However, new technolog y and design practices in lighting offer more potential than identified fi ve years ago. In additi on, the Sixth Power Plan identifies savings in areas not addressed in th e Fifth Power Plan, incl uding interior lighting controls, outdoor lighting, street and highway lighting, and computer server rooms. A summary of the supply curves by major end-use category is shown in Figure 4-4.Chapter 4: Conservation Suppl y Assumptions Sixth Power Plan

4-10 Lighting efficiency measures top the list of comme rcial conservation poten tial. Improvements in fluorescent lights, fixture efficien cy, lighting controls, and improve d lighting design contribute to the large and low-cost potential available for indoor lighting. The availab ility of new lights such as light-emitting diodes (LED) and improved em erging technologies such as ceramic metal halide lighting also contribute to the large lighting conserva tion potential. For example, streetlight, parking lot, and outdoor-area lighting can now take advantage of emerging LED technology in certain applications and reduce consumption 25 to 50 percent.

Figure 4-4: Achievable Commercial S ector Savings Potential by 2029 (MWa) by End Use and Levelized Cost

0 200 400 600 800 1000 1200 1400 1600

<0 20 40 60 80 100 1 2

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Levelized Cost (2006$/MWh)Achievable Potential - by 2029 - (MWa) Process Exterior Light HVAC Interior Light

Nearly two-thirds of commercial-sector conserva tion potential identified in the Sixth Power Plan is lost-opportunity conservation. The increase in lost-opportunity conser vation compared to the Fifth Power Plan is primarily due to a revised approach to modeling natural lighting stock turnover as a lost-opportunity c onservation measure. Retrofit conservation is more expensive than lost-opportunity conservation, so overall costs of commercial conservation are somewhat
lower than in the Fifth Power Plan. Two-thirds of the conservation potential costs less than $40 per megawatt-hour.

Much of the remaining conservation potential in the commercial sector requires a high degree of human intervention to achieve it. For example, car eful choice of lamp, balla st, fixture, control, and layout are needed to inst all highly efficient lighting sy stems with excellent visual
characteristics. In order to increase a buildin g’s efficiency beyond ener gy code requirements, improved building design practices are also needed. Relatively sophisticated HVAC engineering, smart control systems, and careful sy stem operations are needed to harvest much ofChapter 4: Conservation Suppl y Assumptions Sixth Power Plan

4-11 the low-cost HVAC energy savings. In addition, the commercial sector is complex, with a variety of decision makers and market channels that can deliver high-efficiency equipment and well-trained designers and system operators. Implementation strate gies will need to take these
factors into consideration in th e design of efficiency programs and market interventions.



## Industrial Sector

In the Fifth Power Plan, the industrial sector’s potential was estimated to be 5 percent of 2025 sales, or 350 average megawatts. For the Sixt h Power Plan, the Council, with financial support from the Bonneville Power Administration, contract ed an in-depth study of industrial-sector potential. The industrial-sector conservation assessment evaluate s 63 conservation measures and practices as they apply to 19 No rthwest industries. This resear ch indicates potential savings of nearly 800 average megawatts by 2029. Industrial savings are low cost. Nearly all of the savings have levelized costs of less than $50 per megawatt-hour. Almost half the savings costs $20 per megawatt-hour or less. Figure 4-5 s hows the savings achievable by 2029 in the
industrial sector.

Figure 4-5: Achievable Industrial S ector Savings Potential by 2029 (MWa) by Levelized Cost

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Savings vary by industry both in average megawatts and as a fraction of industry electric use. The pulp and paper industry ha s the largest overa ll potential for electric savings, over 300 average megawatts. The food processing and food st orage industries are the second largest with about 200 average megawatts of potential. Savings as a fraction of electricity use range from 4 percent in foundries to nearly 25 percent. Savings fractions are relatively high in the food processing and storage industries. These faci lities use large amounts of electricity for refrigeration, freezing, and controlled-atmosphere storage. Significant efficiency improvements are available for those end-uses. Sectorwide, pot ential savings are about 15 percent of industry electric use. Figure 4-6 shows sa vings for the industry subsectors.Chapter 4: Conservation Suppl y Assumptions Sixth Power Plan

4-12 Figure 4-6: Achievable Industrial Sector Savings Potential by Industry Subsector

0 20 40 60 80 100 120 140 160

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c ha

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The 63 measures include an array of efficient equipment, improved operations and maintenance, demand reduction, system-sizing, system optim ization, and improved business management practices. About one-quarter of the savings are specific to industry subsec tors such as refiner plate improvements in mechanic al pulping, or refrigeration improvements in frozen food processing. About three-quarters of the savings are applicable in pump, fan, compressed air, lighting, and material handling systems that occu r across most industry subsectors. For these measures, the savings come primarily from more efficient equipment and system optimization.
The assessment also found that effective busin ess management practic es can significantly increase equipment and operational savings.

Most industrial conservation measures are comple x and require considerable design and careful implementation. Many measures and practices need continuing management and operational attention to ensure continued saving s. The human factor to achieve these savings is also critical. Implementation strategies will need to take thes e factors into consideration in the design of efficiency programs and market interventions.



## Utility Distribution Systems

Potential savings from utility distribution syst ems come from a NEEA project to improve the efficiency of utility distribution systems. Based on the results of a pilot program in six utilities across the region, the study demonstr ated that operating a utility di stribution system in the lower portion of the acceptable voltage range (120- 114 volts) saves energy, reduces demand, and reduces reactive power requireme nts without hurting the custom er. As a package, these
measures are referred to as conservation voltage reduction.Chapter 4: Conservation Suppl y Assumptions Sixth Power Plan

4-13 Reducing excess voltage saves energy for both th e customer and the utility. Savings could amount to about 400 average megawatts by 2029. Levelized costs for distribution savings are low. Figure 4-7 shows that two-th irds of potential savings cost le ss than $30 per megawatt-hour.

These savings stem from several types of cha nges to distribution equi pment and operations. They include system improvements that reduce primary and secondary line losses, optimize reactive power management on substation feeders and transformers, and balance feeder voltage and current. These improvements help limit th e total voltage drop on the feeder from the substation to the customer’s meter while stayi ng within industry standa rds. The NEEA study results indicate energy savings of 1 to 3 percen t, a kilowatt peak-demand reduction of 2 to 5 percent, and a reactive power reduction of 5 to 10 percent. Approximately 10 to 40 percent of the savings are on the utility side of the meter.

There are a number of barriers, however, to implementing voltage regulation. These include regulatory disincentives, the need for outside assistance, lack of verification protocols to prove savings, and organizational challenges within ut ilities. The Council believes most of these
barriers can be addressed and that near-term savings are achievable.

Figure 4-7: Achievable Utili ty Distribution System Effici ency Savings Potential (MWa) by Levelized Cost

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## Consumer Electronics

Consumer electronics, such as te levisions, set top boxes (digital video recorders, satellite and cable television tuners, digital television converters), computers and monitors, is one of the fastest growing segments of electricity use in th e region. This increase is driven by both the growth of these devices and the additional features that increase energy use. For example, in 2007, the number of televisions in the average home exceeded (2.73) the average number of occupants (2.6) for the very firs t time. If current trends cont inue, it is anticipated that by 2015Chapter 4: Conservation Suppl y Assumptions Sixth Power Plan

4-14 over 90 percent of the televisions sold will ha ve screen sizes exceeding 32 inches. Energy consumption increases with screen size.

There are a significant number of options availabl e to increase the efficiency of these devices. Some of these options simply involve better power management of this equipment when it is not in use. Other options, especially for televi sions and computer monitors, will involve the transition from plasma and liquid crystal displa y (LCD) screens to LED and OLED screens. LED televisions already on the market consume 40 percent less than comparably sized models using LCD technology, while also pr oducing a higher quality picture.

Figure 4-8 shows the achievable potential from improvements in consumer electronics totaling 825 average megawatts by the year 2029. Most of the savings potential, over 700 average megawatts, is available at a levelized life-cycl e cost of less than $60 per megawatt-hour. Moreover, as can be seen in this figure, ove r half of these savings are from improving the efficiency of televisions.

Figure 4-8: Consumer Electronics S avings Potential by Levelized Cost

- 100 200 300 400 500 600 700 800 900

< 0 <20 <40 <60 <80 <100 <120 <140 <160 <180 <200
Real Levelized Cost (2006$/MWH)Regional Achievable Savings by 2030 (MWa) Energy Star Commercial Desktop Computer
Monitors

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Monitors

Energy Star Commercial Desktop Computers

Energy Star Residential Desktop Computers

Energy Star Set Top Boxes

Energy Star Televisions



## ESTIMATING THE AVAILABILITY OF CONSERVATION OVER
TIME

The Council establishes c onstraints on the availability of the conservation in these supply curves,
which are used in the Council’s portfolio modeling process. The portfolio model selects the quantity and timing of both generating and c onservation resource deve lopment. Because significant quantities of conservatio n are available at costs below most forecasts of future marketChapter 4: Conservation Suppl y Assumptions Sixth Power Plan

4-15 prices, the portfolio model would deploy all of the low-cost conservatio n immediately, unless the pace of conservation deployment is constrained to achievable rates.

Therefore, the Council establishes two types of constraints on the amount of conservation available for development. The first constraint is the maximum achievable potential over the 20- year period covered by the Council’ s power plan. The Sixth Power Plan assumes that no more than 85 percent of the technically feasible and cost-effective savings can be achieved. 5

The second constraint is the rate of annual deployment, wh ich represents the upper limit of
annual conservation resource deve lopment based on implementation capacity. Such constraints
include the relative ease or difficulty of market penetrati on, regional experience with the measures, likely implementation strategies and ma rket delivery channels, av ailability of qualified installers and equipment, the num ber of units that must be addr essed, the potential for adoption by building code or appliance sta ndards, and other factors.

The upper limit of annual conservation resource de velopment reflects the Council’s estimate of the maximum that is realistically achievable. Si nce there is no perfect way to know this limit, the Council used several approaches to devel op estimates of annual achievable conservation limits. First, the Council review ed historic regional conserva tion achievements and considered total achievements, as well as y ear-to-year changes. The Council also considered future annual pace constraints for the mix of conservation me asures and practices on a measure-by-measure basis. As in the Fifth Power Plan, annual deploy ment limits were developed separately for lostopportunity and non-lost oppor tunity conservation.



## The Pace of Historic Co nservation Achievements

Over the last 30 years, the region acquired ne arly 4000 average megawatts in energy savings. Annual rates of conservation acquisition vary co nsiderably. Figure 4- 9 shows the Council’s estimate of cumulative regional conservati on achievements since 1978. Figure 4-10 shows annual program conservation acquisitions si nce 1991, excluding savings from codes or
standards.

5 In 2007, Council staff compared the region’s historical achievements against this 85 percent planning assumption. The results of this review supported continued use of the estimate, or perhaps even the adoption a higher one in the Sixth Power Plan. The paper is on the Council website at http://www.nw council.org/library /2007/2007- 13.htm.Chapter 4: Conservation Suppl y Assumptions Sixth Power Plan

4-16 Figure 4-9: Cumulative Regional Conservation Achievement 1978-2008 (MWa)

0 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000

1 978 1 980 1 982 1 984 1 986 1 988 1 990 1 992 1994 1996 1998 2 000 2 002 2004 2006 2008

YearCumulative Savings (MWa) Federal Standards

State Codes
NEEA Programs
BPA and Utility Programs

Over this 30-year period, the mix of measures has changed significantl y. Early years were dominated by residential programs. In th e 1990s, commercial and industrial programs were added. Starting in the mid-1980s, state building codes began to capture significant savings. About five years later, federal appliance standards also added savings. Fluctuations in annual achievements, shown in figure 4-10, were caused by many factors. For example, response to the energy crisis of 2000-2001 brought on a surge in conservation achievement, more than doubling the annual conservation acquisition rate betw een 2000 and 2001. And the threat of retail competition in the late-1990s was a key factor in the drop in utility-sponsored conservation activity in that period.

Over the last 20 years, state building codes a nd federal and state appl iance standards have accounted for over one-third of all savings. Sa vings from codes and standards accumulate slowly over time. They do not result in large annual jumps in acquisition because they apply only to new buildings or replacement equipment. Furthermore, code and standard savings would not have been possible without ut ility programs that demonstrated the savings could be achieved.

Bonneville, utility, and Energy Trust of Oregon conservation programs, Oregon tax credits, NEEA market transformation, a nd other programs have delivere d the bulk of the savings over time. Annually, these program savings ranged from lows of about 60 average megawatts per year to 235 average megawatts per year in 2008, the most recent year reported. Since 2001, regional programs, without codes and standards, delivered about 150 average megawatts per year on average. Annual rates of program acqui sition since 2001 have been between 115 to 235 average megawatts per year, which is consiste ntly higher than long- term annual rates for program delivery.Chapter 4: Conservation Suppl y Assumptions Sixth Power Plan

4-17 Figure 4-10: Annual Conservation Achi evements from Programs 1991-2008 (MWa)

0 50 100 150 200 250

19

9 1 1992 19 93 19 94 19 9 5 1 9 96 1 9 97 19 98 1999 2000 20 01 20 0 2 20 0 3 2 0 04 2 0 05 20 06 2007 2008Incremental Savings (MWa) NEEA

BPA and Utility Programs

There were three historic periods when progr am savings showed fast acceleration. The 1991- 1993 period, the 2000-2001 period, and more re cently the 2005-2008 period. During these periods, regional program activities increased by over 40 average megawatts year-to-year, not counting codes and standards.

The Regional Technical Forum's survey of 2008 conservation achievements indicate that regional program savings alone are 235 averag e megawatts. Consequently, recent savings exceed the targets established in the Fifth Power Plan by a wide margin. The Fifth Power Plan’s called for a cumulative 700 average megawatts between 2005 and 2009 through all mechanisms. If conservation acquisition continues to accelera te, it appears that the region will capture over 900 average megawatts through just Bonneville a nd utility programs alone, exceeding the targets by about 30 percent.



## Estimating the Annual Availability of Future Conservation Development

To gauge the pace for future conservation deve lopment, the Council es timated how fast the region could develop the remaini ng conservation measures identifie d in the Sixth Power Plan. To do this, the Council estimated year-by-year ac quisition rates for each of the measure bundles
identified in the conservation assessment.

The results of this year-by-year and measure-by- measure analysis are only one indication of how fast the region could deploy conservation. Cl early, deployment efforts could shift from the assumptions made in this analysis. Acquisitions of specific measure bundles could accelerate orChapter 4: Conservation Suppl y Assumptions Sixth Power Plan

4-18 slow down. Nevertheless, the annual limits give some idea of how fast conservation could be brought on line with multi-year acquisition strate gies, ramp-up rates for new programs, and a more or less steady pa ce in the long run.

There are about 200 measure bundles that were cons idered in this analys is. Details of these assumptions are in the conservation appendices.

In estimating the level of conservation that could be achieved in the future, the Council
considered several factors. For all measure bundles, the Council assumed multi-year acquisition plans. Depending on the measure, getting to full pene tration could take as little as five years or as long as 20 years. The Council also consid ered retrofit and lost-opportunity measures differently. Table 4-2 shows the results of the year- by-year, measure-by-measure approach used to estimate the pace of conservation developmen t. Energy savings represent total potential, regardless of cost.

Table 4-2: Achievable Pace of Future Conservation Development Approximate Savings Potentia l by Time Period (MWa) Lost Opp Non-Lost Opp Total 20-Yr Cumulative 3,400 3,300 6,700 5-Yr Cumulative (2010-2014) 390 990 1,380 5-Yr Annual Ramp Up 35 to 120 170 to 220 200 to 340 5-Yr Annual Average 80 200 280

Most retrofit measures were paced at annual acq uisition rates that require 15 to 20 years to accomplish. However, it was assumed that some retrofit measure bundles with simple, proven delivery mechanisms, like low-flow showerheads, could be accomplished in as little as five years. Annual acquisition rates for new retrofit initiatives or measures that have not been targeted previously, such as distribution-efficien cy, were estimated to start slowly and accelerate to a steady annual pace. As a result, these new retrofit measures account for only about 20 percent of this five-year total because low pene tration rates were assumed in the early years.

Measures that are already targeted by current programs were assumed to accelerate from a higher starting point. Across all retrof it opportunities the available po tential increases from about 170 average megawatts in 2010 to 220 average mega watts per year by 2014. In aggregate, this results in nearly 1,000 average megawatts of retr ofit conservation viewed as available potential in the first five years. This is about one-th ird of the Council’s 3,300 average megawatt retrofit supply curve. At an average pace of only 160 av erage megawatts per year, it would take about 15 years to acquire the 2,400 average megawatts of retrofit potential that ha s an average cost less than $30 per megawatt-hour.

For lost-opportunity measures, it was assumed that the maximum achievable pace of acquisition never exceeds 85 percent of the annual units avai lable. The bulk of lost-opportunity measures were assumed to take five to 15 years to reach this 85 percent annual penetration rate. Lower (0.5 to 15 percent) first-year pe netration rates were assumed fo r lost-opportunity resources new to regional programs because acquiring these measures is slower given the relative difficulty of deploying them. For lost-opportu nity measures where the regi on has experience and for ongoing programs, such as residential appliances, first- year penetration rates we re set relatively higher and with a faster ramp-up rate over time.Chapter 4: Conservation Suppl y Assumptions Sixth Power Plan

4-19 The annual acquisition for all lost-opportunity cons ervation measures start at a penetration rate of about 15 percent, increases to around 80 percent in 12 ye ars, and reaches the assumed maximum 85 percent in 15 years. In aggregate, this results in about 390 average megawatts of available savings potential from lost-opportunity conser vation resources over the first five years covered by the Sixth Power Plan. About one-third of these savings are from new measures in the plan. The maximum annual pace for lost-opportun ity conservation accelerates from 35 average megawatts per year in 2010 to 120 average megawa tts per year five years out, and to 200 average megawatts per year 10 years out.

In combination, this analysis in dicates that nearly 1,400 average megawatts of lost-opportunity
and retrofit conservation are available over th e 2010-2014 action plan period. Maximum annual average acquisitions increase from 200 average megawatts per year in 2010 to almost 350 average megawatts per year within five years. The estimates of acquisition rates produced by this analysis are used to estimate annual pacing constraints in the portfolio model. Along with information on historic performance, and utility and NEEA plans, these estimates also help inform the Council’s near-term conservation targets for the region.



## Testing Annual Pace Constrai nts for the Portfolio Model

Because the maximum annual pace of conservation achievement is to a major extent a function
of the level of resources dedi cated to acquiring conservation, the Council performed sensitivity tests to estimate the impact of achieving conservation faster and sl ower than assumed in the base case. For a high-case sensitivity, the Council assu med a 10-year period to develop the first 2,400 average megawatts of retrofit conservation, instead of the 15 years assumed in the base case. This means an average pace of 220 average megawatts per year for retrofit conservation and no increase in the ramp-up for lost-opportunity conservation. For the low-case sensitivity, the Council assumed that no more than 100 average megawatts per year of retrofit conservation could be developed, and the lost -opportunity ramp-up would take 20 years to reach 85 percent annual penetration, instead of 15 years in the base case. At the hi gh-case sensitivity, 1,500 average megawatts could be developed over the firs t five years of the action plan. For the lowcase only about 800 average megawatts would be deve loped in the five years of the action plan. The results of these sensitivity tests are discussed in Chapter 10.

Figures 4-11 and 4-12 show the maximum annual conservation rates used as the base case assumptions and the high- and low-c onservation sensitivity cases.Chapter 4: Conservation Suppl y Assumptions Sixth Power Plan

4-20 Figure 4-11: Maximum Conservation Acquisition Rates Tested for Non-Lost-Opportunity
Conservation

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Figure 4-12: Maximum Conservation Acquisi tion Rates Tested for Lost-Opportunity
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## COUNCIL METHODOLOGY

The Northwest Power Act establishes three criteri a for resources included in the Council’s power plans: resources must be 1) reliable, 2) available within th e time they are needed, and 3) available at an estimated incremental system cost no greater than that of the least-cost similarlyChapter 4: Conservation Suppl y Assumptions Sixth Power Plan

4-21 reliable and available alternative. 6 Beginning with its first power plan in 1983, the Council interpreted these requirements to mean that cons ervation resources included in the plans must be:

• Technically feasible (reliable)

• Economically feasible (lower cost)

• Achievable (available)

Development of the conservation potential assessment takes into account an assessment of what has been accomplished and what remains to be done. The first step in the Council’s methodology is to identify all of the technically feasible potentia l conservation savings in the region. This involves reviewing a wide arra y of commercially avai lable technologies and practices for which there is documented evidence of electricity savings . Over 300 specific
conservation measures were evaluated in deve loping the conservation potential for the Sixth Power Plan. This step also involves determin ing the number of potentia l applications in the region for each of these technologi es or practices. For example, electricity savings from highefficiency water heaters are only “technically feasible” in homes that have, or are forecast to have, electric water heaters. Similarly, incr easing attic insulation in homes can only produce electricity savings in electrically heated homes that do not already have fully insulated attics. At the conclusion of this step, the Council’s load forecast and conservation assessment are adjusted and calibrated to reflect changes in baseline conditions since the adop tion of the Fifth Power
Plan.

The Sixth Power Plan’s assessment reflects pr ogram accomplishments, changes in codes and standards, technological evoluti on, and the overall adoption of mo re energy-efficient equipment and practices since the Fifth Power Plan was adopted in 2004. There are five significant changes:

1. Accounting for utility conserva tion program savings since 2004.

2. Adjusting both the load forecast and the c onservation assessment to reflect improvements
in federal and state standards for lighting and appliances.

3. Adding potential savings from utility distribut ion efficiency improvements and consumer
electronics.

4. Increasing potential industrial saving s from a more in-depth analysis.

5. Adding potential savings from new technologies and practices that have matured to commercial readiness since the Fifth Power Plan’s estimates were developed.

6 See Section 839a(4)(A)(i) and (ii) of the Northwest Power Planning and Conservation Act. ( http://www.nwcouncil.org/libra ry/poweract/3_definitions.htm or http://www.nwcouncil.org/LIBRA RY/poweract/poweract.pdf)Chapter 4: Conservation Suppl y Assumptions Sixth Power Plan

4-22 

## Implications for the State of Washington’s I-937 Requirements

Initiative 937 (I-937) in the st ate of Washington, approved by the voters in 2006, obligates 17 utilities that serve 88 percent of the retail load in that state to “pursue all available conservation that is cost-effective, reliable, and feasible.” By January 2010, each utility the law applies to must develop a conservation plan that identifie s its “achievable cost-eff ective potential” for the next 10 years, “using methodologies consistent w ith those used by the Pacific Northwest electric power and conservation planning council in its most recently pub lished regional power plan.” Every succeeding two years, the utility must review and update its assessment of conservation potential for the subs equent 10-year period.

I-937 is a matter of state law, and does not alte r or obligate the Council in its conservation and power planning under the Northwest Power Act. Similarly, the Council has no authority to interpret, apply or implement I- 937 for the utilities and regulators in the state of Washington.
But because the two mandates intersect--the st ate’s utilities are to engage in conservation planning “using methodologies cons istent with” the conservation planning methodology used by the Council--it is helpful to unders tand some of the issues raised by the two planning processes.

There is some misunderstanding th at I-937 requires Washington util ities to meet some pro-rata share of the conservation targets in the power plan. In fact, I-937 does not require the state’s utilities to adopt or meet cons ervation targets set forth in the Council’s plan, nor does the plan identify any particular utility’s “share” of regional conservati on targets. However, I-937 does require utilities to develop their own plan us ing methods “consistent with” the methodology used in the Council’s plan, leaving it to the utilities’ discretion to adapt the planning methods to their particular circumstances. To a ssist Washington consumer-owned utilities in this effort, the Washington Department of Commerce (Commerce), 7 with the assistance of the Council staff and others, adopted rules in 2008 outlining the me thodology the Council uses in its conservation planning. Although one sub-section of these rules allows utili ties to adopt a share of the Council’s regional targets, this is an option, not a requirement. The Wa shington Utilities and Transportation Commission (UTC) also adopted ru les to guide the investor-owned utilities. These rules are not as prescrip tive and, per the law, integrat e I-937 requirements into ongoing regulatory practice.

Concern has also been expressed about the fact th at utilities will need to produce their first I-937 conservation plans at the precise moment the Co uncil is making the transition from the Fifth to the Sixth Regional Power Plan. On this i ssue we should point out that the Council’s methodology is essentially the same in the Sixth and Fifth Power Plans and is clearly described in Chapter 4 of this draft. The conservation targ ets are higher in the Sixth Power Plan because of changes in prices, technology, and other fact ors, not because of a change in methodology.

The Council’s plan describes the analytical me thods used to identify cost-effective achievable conservation and provides a menu of possible cost-e ffective measures for utilities to consider. Neither I-937 nor the Council’s pl an requires utilities to choose any of the plan’s particular measures in particular amounts. The utilities may make that judgment based on their own loads (composition, amounts, and growth rates) and thei r own determination of avoided cost and the
measures available to them.

7 Formerly the Washington Department of Community Trade and Economic Development (CTED)Chapter 4: Conservation Suppl y Assumptions Sixth Power Plan

4-23 There are two issues—“ramping” and “pen etration rates”—that may present potential
inconsistencies between I-937 and the Council’s conservation methodology. An important element in the Council’s methodology is the prin ciple that it takes time to develop certain conservation measures to their full potential, wh ile other measures are available right away. Consequently, conservation potential ramps up and on occasion ramps down. The Council uses its ramp rate assumptions, along with other inform ation and the results of its regional portfolio model, to establish five-year cumulative conserva tion targets for the region. The end result is that achievable conservation potential under th e Council’s planning assu mptions will not be evenly available across each year in the period. I- 937 separately instructs the utilities to identify not just cost-effective potential over the 10-year life of the util ity’s conservation plan for I-937, but also to identity and meet biennial conservation acquisition ta rgets that must be “no lower than the qualifying utility’s pro ra ta share for that two-year peri od of its cost-effective potential for the subsequent 10-year period.” Having to ac quire 20 percent of any 10-year target in any two-year period under I-937 may produce different two-year targets than would result using ramp rates consistent with the Council’s met hodology. Commerce rules do not address what is meant by “pro-rata share,” but the UTC rules state that “‘pro rata’ means th e calculation used to establish a minimum level for a conservation targ et based on a utility’s projected ten year conservation potential.” Because the provisions of I-937 are a matter of state law, this issue is
not one that the Council can resolve in its plan.

A related, but distinct, issue concerns conservati on measure “penetration” rates. Part of the Council's methodology is to estimate the extent of total penetration of a conservation measure in the area of study over the to tal period analyzed. The Commerce rules address th is issue, calling on utility conservation plans to “[i]nclude estimates of the achievable customer conservation penetration rates for retrofit measures and for lo st-opportunity (long-lived) measures.” Because, as with “ramp rates,” I-937 re quires a ten-year plan while th e Council produces a twenty-year plan, the rules needed to harmonize the potential difference between pene tration rates over ten years versus penetration rates ov er twenty years. As a result , the Commerce rules then go on to describe the Council’s 20-year a nd 10-year penetration rates (from the Fifth Plan, although they do not differ in the Sixth Plan), “for use when a utility assesses its” conservation potential. The UTC rules are silent on penetration rates.

One final point to consider is the treatment of savings achieved through building codes and other
standards. The Council’s conservation met hodology calculates the conservation potential for measures that might, at some point, be covere d by building codes or energy codes, and then assumes that the savings will be accomplished over time by either utility programs or codes. If codes are adopted that ensure the capture of the potential sa vings, then those savings are “counted” against the regional target. The ru les adopted by Commerce for I-937 do not appear to be inconsistent with this approach while the UTC rules do not address this issue specifically.Sixth Northwest Conservation and Electric Power Plan 

# Chapter 5: Demand Response

Summary of Key Findings........................................................................................................ ...... 1 Demand Response in the Fifth Power Plan..................................................................................... 2 Progress Since the Fifth Power Plan........................................................................................... 3 Demand Response in the Sixth Power Plan.................................................................................... 3 Estimation of Available Demand Response ............................................................................... 3 Demand Response Assumptions................................................................................................. 5
Studies of Potential ........................................................................................................... ...... 5 Experience..................................................................................................................... .......... 6 Council Assumptions............................................................................................................ .. 8 Caveats for Demand Response Assumptions ....................................................................... 11 Ongoing Analysis with the Regional Portfolio Model ......................................................... 11 Pricing Structure .............................................................................................................. ......... 12 Providing Ancillary Services with Demand Response ............................................................. 12 Contingency Reserves........................................................................................................... 13 Regulation and Load Following............................................................................................ 13



## SUMMARY OF KEY FINDINGS

The Council’s definition of demand response (DR) is a voluntary and temporary change in consumers’ use of electricity when the power system is stressed. The change in use is usually a reduction, although there are situations in which an increase in use would relieve stress on the power system and would qualify as DR.

Demand response could provide value to our power sy stem in four forms. It can provide a form of peaking capacity by reducing load a few hours a y ear at peak load. It can provide contingency reserves, standing ready to interrupt load if unscheduled generation outages occur. Some demand response could provide flexibility reserv es (e.g. load following) by decreasing or increasing load as needed to accommodate small e rrors in scheduling in vi rtually all hours of the year. Finally, some demand response could absorb and store energy when its cost is low and return the energy to the system a few hour s later when its value is higher.

This plan assumes, based on experience in th e region and elsewhere, that the achievable technical potential for demand resp onse in the region is around 5 percent of peak load over the 20-year plan horizon. The plan assumes 1,500 to 1,700 megawatts of load reductions in the winter and summer, respectivel y, and 2,500 to 2,700 megawatts of load reductions together with dispatchable standby generation. This achievable technical potential was included in analysis by the Council’s Regional Portfolio Model 1 to determine how much demand response is included in the preferred-resource portfolios identified by the model.

The region still lacks the expe rience with demand response to construct a detailed and comprehensive estimate of its potential. To make that estimate possible, the region will need to conduct a range of pilot programs involving demand response. These pilots should pursue two general objectives, research and development/demonstration.

1 See Chapter 9 for a description of this analysis.Chapter 5: Demand Res ponse Sixth Power Plan

5-2 “Research pilot programs” should explore areas th at have not been tried before. These pilot programs should be regarded as programs to buy essential information. They should not be designed or evaluated based on how cost-effective each pilot is on a stand-alone basis, but rather based on how much the information gained from each pilot will contribut e to a long run demandresponse strategy that is cost-effective overall. Ideally regional utili ties and regulators will coordinate these research pilots to avoid duplic ation of effort. Regulators should allow cost recovery of pilots that cont ribute to such a strategy.

The region should also pursue “development and demonstration pilot programs” that are designed to test acquisition stra tegies and customers’ reactio ns to demand-response programs that have been proven elsewhere. These pilo ts will allow the region to move to full-scale acquisition of some elements of demand response while the research pilots expand the potential by adding new elements. The development and de monstration pilots should be designed and
evaluated with cost-effectivene ss in mind, but with the recogn ition that the product of these pilots includes experience that can make th e acquisition program mo re cost-effective.

Both the research pilots and the development and demonstration pilo ts should include projects to test the practicality of demand response as a source of ancillary services.



## DEMAND RESPONSE IN THE FIFTH POWER PLAN

The Council first took up demand response as a potential resource 2 in its Fifth Power Plan (May 2005). 3 The Fifth Power Plan expl ained that concern with demand response rises from the mismatch between power system costs and consum ers’ prices. While power system costs vary widely from hour to hour as demand and supply circumstances change, consumers generally see prices that change very little in the short term. The result of th is mismatch is higher consumption at high-cost times, and lower consumption at low-cost times, than is optimal. The ultimate result of the mismatch of costs and prices is that the power system needs to build more peaking capacity than is optimal, and uses base-load ge neration less than is optimal. Programs and policies to encourage demand response are efforts to correct these distortions.

The Fifth Power Plan described pricing and pr ogram options to encourage demand response, made a very rough estimate of 2,000 megawatts of demand response that might be available in the Pacific Northwest over the 2005-2025 period, and described some estimates of the costeffectiveness of demand response. The plan conc luded with an action plan to advance the state of knowledge of demand response.

The Fifth Power Plan’s treatment of demand response is laid out in more detail in Appendix H of this plan, with references to rele vant parts of the fifth plan.

2 According to the strict legal definitions of the Northwes t Power Act, demand response is probably not a “resource” but a component of “reserves.” For ease of exposition, the plan refers to demand response as a resource in the sense of the general definition of the word - “a source of supply or support.”

3 The Fifth Power Plan is posted at http://www.nwcouncil.org/ener gy/powerplan/5/Default.htm , with Chapter 4 on
DR at http://www.nwcouncil.org/energy/powerplan/5/(04)%20Demand%20Response.pdf and Appendix H on DR at http://www.nwcouncil.org/ener gy/powerplan/5/Appendix%20H%20(Demand%20Response).pdfChapter 5: Demand Res ponse Sixth Power Plan

5-3 

## Progress Since the Fifth Power Plan

Since the release of the Fifth Power Plan, the re gion has made progress on several fronts. Idaho Power, PacifiCorp and Portland General Elect ric have expanded existing demand-response programs. Portland General Electric and Idaho Power have begun to install advanced metering for all their customers, which facilitates de mand response programs and enables time-sensitive pricing. Many utilities in the region now are treating demand re sponse as an alternative to peaking generation in their in tegrated resource plans.

The Council and the Regulatory Assistance Projec t (RAP) have worked t ogether to coordinate the Pacific Northwest Demand Response Project (PNDR P), composed of partie s interested in the stimulation of demand response in the region. Th e initial focus of PNDRP has been on three primary issues: defining cost-eff ectiveness of demand response, di scussing a role for pricing, and considering the transmission and distribution system costs that can be avoided by demand

response.

PNDRP adopted guidelines for cost-effectiveness evaluation that are included in Appendix H.Agreement on these guidelines is a major accomplishment by the region. These costeffectiveness guidelines provide an initial valuation framewor k for demand-response resources and should be considered as a screening tool by state commissions and utilities in the Pacific Northwest. PNDRP has begun the considerati on of price structures encouraging demand

response.

The Council has extended its anal ysis of demand response, examining the effect of the cost structure of demand response (i.e. high fixed cos t/low variable cost as compared to low fixed cost/high variable cost) on its attractiveness in resource portfolios. This analysis takes into account the benefits of demand response in redu cing risk, which other analyses tend to overlook.

The region’s system operators also have become increasingly concerned with the system’s ability to achieve minute-to-minute balancing of incr easingly peaky demands for electricity against generating resources that include increasing amounts of variab le generation such as wind. Demand response is recognized as a potential source of some of th e “ancillary services” necessary for this balancing.

These areas of progress are covered in more detail in Appendix H.



## DEMAND RESPONSE IN THE SIXTH POWER PLAN

Estimation of Available Demand Response

The region has gained much experience in the estim ation of conservation pot ential over the last 30 years, but demand-response analysis is still in its infancy. For conservation the general approach has been to compile a comprehensive li st of conservation measures, analyze their costs and effects, and arrange them in order of increa sing cost per kilowatt-hour. Given the resultingChapter 5: Demand Res ponse Sixth Power Plan

5-4 supply curve, planners can identify all conservati on measures that cost less than the marginal generating resource. 4

Estimating demand response potential using a similar approach makes perfect sense, and it is the Council’s strategy. However, demand response presen ts some unique problems to this approach. Some of the features that make estimating a supply curve for demand response more complex than estimating one for conservation are listed belo w and treated in more detail in Appendix H.

• The amount of available demand response vari es with season, time of day, and power system conditions. For example, on an August afternoon customers can accept higher temperatures to reduce air-conditioning load, but that response is not available when there is little or no air-conditioning load, such as the cool night hours in most months.

• Demand response can provide a variety of serv ices to the power system (e.g. peak load service, contingency reserves, regulation, load following) as described in Appendix H.
Each of these services will have its own s upply, which will vary over time. To estimate a supply curve for demand response to help meet peak load, we must consider whether
some of the same customers and actions will be providing contingency reserves or loadfollowing services as well -- otherwise we run the risk of counting th e same actions twice in separate supply curves.

• The costs of demand response are more complex than those of conservation. The costs of conservation are generally fixed, as are the am ount and schedule of energy savings. In contrast, demand response ofte n comes with fixed and vari able cost components, and requires a “dispatch” decision (by the utility or the customer) to reduce energy use at a particular time. The variable cost of demand re sponse is the major factor in that decision.

• Displaying demand response in the normal co st-vs.-quantity format of a supply curve requires some sort of aggregation of the fixe d and variable costs into a single measure, such as the “average cost per megawatt of a demand-response program that operates 100 hours per year.” But a supply curve displaying such aggregated costs may distort critical information about a demand-response program . In this example, depending on the variable cost of the program, it may or may not make sense to operate it the assumed 100 hours per year.

• Estimates of conservation potential usua lly have depended on understanding the performance of “hardware” such as insula tion and machinery, predictable through an engineering analysis. Estimates of dema nd response, on the other hand, depend more on understanding the behavior of consumers exchanging comfort or convenience for compensation. This behavior is not so pred ictable without actual experience, which so far is quite limited.

• The economics of demand response will be powerfully influenced by technological change, particularly the developmen t of “Smart Grid” technologies, 5 which promise to make more and cheaper demand response avai lable. Such technological change is impossible to predict in specifics, but it seem s inevitable that there will be significant

4 The methodology for estimating conservation potential is described in more detail in Appendix E.

5 See Appendix K.Chapter 5: Demand Res ponse Sixth Power Plan

5-5 change over the next 20 years, and that the change will make demand response more
attractive.



## Demand Response Assumptions

With the limited experience available now, a bala nce must be struck between the precision and the comprehensiveness of estimates of potential demand respons e. Precise estimates need to be limited to customers, end uses, and incentives where there is experience. These estimates necessarily exclude some possibi lities that are virtually certain to have significant demand potential, eventually. Comprehensive estimates avoid this tendency to underestimate potential by including possibilities where there is less e xperience, and the estimates are therefore less precise.

Each of these approaches has its place. An es timate for a near-term implementation plan must focus on the “precise” end of this spectrum. An estimate for a long-run planning strategy, such as the Council’s, should focus on the “comprehe nsive” end. The long-term goal should be to expand experience with various forms of demand re sponse to the point that a precise estimate of available demand response is also comprehensive. It’s fair to say this goal has been reached in the estimation of conservation potential, but ha s not yet been reached for demand response, at least for the region as a whole.



### Studies of Potential

With these caveats about the limitations of estimating potential demand response based on limited experience, the regional discussions and analysis since the Fifth Power Plan have advanced our understanding of the resource. In the Northwest, st udies of potential have been contracted by the Bonneville Power Administra tion, PacifiCorp, Portland General Electric, and Puget Sound Energy.

Global Energy Partners and The Brattle Gr oup performed Bonneville’s study. The study estimated demand response available through 2020 and included direct load control of residential and small commercial customers, an “Emergency Demand Response” 6 program for medium and large commercial and industrial cu stomers, capacity market options, 7 customers’ participation in a market for ancillary services, and two pric ing options. The study estimated potential demand response for each of these options. The estima tes took each option alone, with no attempt to estimate the interactions among th em -- as a result, adding the estimates together risks double counting some demand response.

Council staff extended this study’s results for di rect load control, emergency demand response, and capacity market options proportionally to the entire region by assuming that these programs did not double count potential so that they could be summed. The upper end of the range of regional estimates resulting from this extension amounted to about 1.4 percent of peak load in the winter and 2.2 percent of peak load in the summer in 2020.

6 Customers are offered payment for load reductions during system events, but are not pe nalized if their usage does not change.

7 Customers are paid to commit to re duce loads when required by the power system, and receive additional payment when they actually are called to reduce load.Chapter 5: Demand Res ponse Sixth Power Plan

5-6 Puget Sound Energy (PSE) commissioned a study by Ca dmus in 2009 that is still being revised. Preliminary results indicate that demand respons e equal to about 3 percent of 2029 forecast peak
load will be available.

The studies of demand-response potential for Paci fiCorp and Portland General Electric had not been completed at the time the Coun cil issued the Sixth Power Plan.



### Experience
In addition to estimates of demand response avai lable in the future, there is considerable experience around the country with demand response that has been acquired or is in the last stages of acquisition by utilities and system operators. This e xperience gives some idea of the total amount of demand response that can be expe cted when utilities pursu e it aggressively over a period of time. Table 5-1 shows some of this experience. It also shows some scheduled increases in demand response over the next few y ears; these schedules ar e based on expansion of existing programs or signed contracts that make the utilities quite confident that the scheduled demand response will be realized.

In the Pacific Northwest, PacifiCorp has been quite active in acquiring demand response. By 2009, PacifiCorp expected to have over 500 mega watts of demand response, including direct load control of air conditioning and irrigation, dispatch able standby generati on, and interruptible load. PacifiCorp also calls on demand buy-back and “Power Forward.” 8 These last two components are considered non-firm resources, but have combined to provide reductions in the 100 to 200 megawatts range in addition to the 5 00 megawatts of firm megawatts. The demand response, compared to PacifiCorp’s forecas ted peak load of 9,800 megawatts for 2009, means that PacifiCorp has more than 5 percent of peak load in firm demand response, and another 1-2 percent in non-firm demand response.

Idaho Power had about 60 megawatts of dema nd response in 2008, made up of direct load
control of residential air conditioning and timers on irriga tion pumps. The company is committed to achieving a total of 307 megawatts by 2013, pending the expected approval of this plan by the Idaho Public Utilities Commission. This level of demand response would be accomplished by converting much of their ir rigation demand response to dispatchable 9 and adding demand response from the commercial and industrial sectors. This level would be 8.1 percent of their projected peak demand in 2013 of 3,800 megawatts. In the longer run the company is planning on reaching 500 megawa tts of demand response by 2021, which would make demand response equal to 11.4 percent of its 2021 forecasted peak demand of about 4,400 megawatts.

Portland General Electric had 53 megawatts of dispatchable standby generation in place in 2009 and expects to have 125 megawatts in place by 2 012. PGE is using it to provide contingency reserve, which only operates when another resour ce is unexpectedly unavailable. This means that while this generation is licensed to operate 400 hours per year, it actually operates a much smaller number of hours per year. PGE also has received responses from a request for proposals

8 Power Forward is a program coordinated with the governor’s office in Utah that makes public service announcements asking for voluntary reductions from the general public when the power system is stressed. Estimated response varies, but has been as much as 100 megawatts.

9 Instead of having reductions on fixed schedules, some customers on Monday, some on Tuesday, etc., the company would be able to call on all of the participating customers at the same time when the need arises.Chapter 5: Demand Res ponse Sixth Power Plan

5-7 to provide demand response up to 50 megawatts by 2012. These responses make the company confident that it can actually secure 50 megawatts of new demand response by 2012. Finally, PGE has 10 megawatts of interruptible contracts with industrial customers. The sum of these three components, 185 megawatts, is equal to 4.1 percent of the company’s projected peak load of 4,500 megawatts in 2012.

Elsewhere in the country, the New York Inde pendent System Operat or (NYISO) has been enlisting and using demand response in its operati ons for several years. The NYISO currently has about 2,300 megawatts of demand response participating in its programs. About 2,000 megawatts of that total are subject to significant penalties if the demand response is not delivered when requested, so should be considered firm resources. About 300 megawatts of the total are voluntary and are better counted as nonfirm, although the typical re sponse of these resources is around 70 percent, according to NYISO staff. The 2,000 megawatts of firm demand response amounts to about 5.9 percent of the NYISO’s expected 2009 peak load of 34,059 megawatts. Adding the expected 70 percent of the 300 megawa tts of non-firm demand response would raise the expected total demand response to 2,210 megawatts, or 6.5 percent of peak load.

The New England Independent System Oper ator (ISO) cited 1,678 megawatts of demand response without dispatchable standby genera tion and 2,278 megawatts of demand response with dispatchable standby generation for 2007. These figures were 6.1 and 8.3 percent of the ISO’s average-weather summer peak load of 27,400 megawatts (winter peak load is 22,775 megawatts). 10

PJM Interconnection is a regional transmission organization that manages a wholesale market and the high-voltage transmission system for 13 mid-Atlantic Coast and Midwest states and the District of Columbia. PJM estimated 4,460 megawa tts of demand response in its control area in 2008 compared to a forecasted peak load of 137,950 megawatts 11 or about 3.2 percent of peak load. There may be some demand response in the uti lities of states that have been recently added to PJM (Illinois, Ohio, Michigan, and Kentuc ky) that is not included in this total.

California dispatched 1,200 megawa tts of interruptible load on July 13, 2006 to help meet a record peak load of 50,270 megawatts. Califor nia had 1,200 megawatts more demand response
available if it had been needed. 12 The 2,400 megawatts of total demand response used and available amounted to 4.8 percent of actual peak load. By 2011 the three investor-owned utilities expect to have at least 3,500 megawatts of demand response av ailable, or 6.5 percent of the California Energy Commission’s forecast of the th ree utilities’ peak loads total for 2011 (53,665 megawatts). 13

10 http://www.iso-ne.com/trans/rsp/2008/rsp08_final_101608_public_version.pdf Table 5-7 page 47, Table 5-8 page 49, and Table 3-3 page 25 11 http://www.pjm.com/documents/~/media/documents/presentations/pjm-summer-2008-reliability-assessment.ashx

12 “Harnessing the Power of Demand: How ISOs and RTOs Are Integrating Demand Response into Wholesale Electricity Markets,” Markets Committee of the ISO/RTO Council, October 16, 2007.

13 The California Energy Commission’s forecast of the three utilities’ peak demands can be found at http://www.energy.ca.gov/2007publications /CEC-200-2007-015/CEC-200-2007-015-SF2.PDF , in the Form 4 table for each utility.Chapter 5: Demand Res ponse Sixth Power Plan

5-8 Table 5-1: Demand Response Ac hieved by System Operator

System Operator Year Achieved/ Scheduled Demand Response as % of Peak Load (Achieved/Scheduled) PacifiCorp 2009 5.1 Idaho Power 2008/2013 1.9/8.1
Portland General Electric 2009/2012 1.4/4.1 New York ISO 2009 5.9 firm, 6.5 expected New England ISO 2007 8.3 PJM 2008 3.2 California ISO 2006/2011 4.8/6.5



### Council Assumptions
Based on these study results and ex perience elsewhere, the Council a dopted cost and availability assumptions for several demand-response programs. For this analysis of long-term planning strategies, the assumptions lean more toward the comprehensive end of the “precise/comprehensive” spectrum. These assu mptions were used in the regional portfolio model to analyze the impact on expected system co sts and risk of alternat ive resource strategies. Accordingly, they can be regarded as achievabl e technical potential, w ith the portfolio model analysis determining the programs and am ounts that are cost- and risk-effective. 14

The Council based its assumptions in part on th e evidence that demand response of at least 5 percent of peak load has been accomplished by a number of utilities and system operators in periods of five to 10 years. Therefore, accomplishing a similar level of total demand response over 20 years in the Northwest is reasonable. Th e total assumed potential brackets the 5-percent level, depending on whether the dispatchable st andby generation is includ ed or not. Without dispatchable standby generation, the assumed pot ential is 1,500 megawatts in the winter and 1,700 megawatts in the summer (about 3.8 perc ent and 4.3 percent of the forecast 40,000- megawatt peak load forecast for 2030, respectivel y). With dispatchable standby generation, the totals are 2,500 megawatts in th e winter and 2,700 megawatts in the summer, or 6.3 percent and 6.8 percent of forecast peak load, respectively.

The assumptions are summarized in Table 5-2. Three further points are worth making about these assumptions. First, they include dema nd response that already has been achieved, amounting to more than 160 megawatts by 2009. Second, they include announced plans to acquire demand response by regional utilities amounting to more than 350 megawatts. Finally, these assumptions are used as long-run assumptions for the portfolio model, and are not targets for short-run utility implementation planning. Targets for implementation result from the portfolio analysis and a strate gy to accumulate experience with demand response, described in the action plan of the power plan.

14 For more information about the portfolio model, see Chapter 9.Chapter 5: Demand Res ponse Sixth Power Plan

5-9 Table 5-2: Demand Response Assumptions

Program MW Fixed Cost Variable Cost or (hours/year limit) Season available Air Conditioning (Direct Control) 200 $60/kW-y ear 100 hours/year Summer Irrigation 200 $60/kW-year 100 hours/year Summer Space heat/Water heat (Direct Control) 200 $100/kW-year 50 hours/year Winter Aggregators (Commercial) 450 $70/kW-year $150/MWh 80 hours/year Summer + Winter

Interruptible Contracts 450 $80/kW-year 40 hours/year Summer + Winter Demand Buyback 400 $10/kW-y ear $150/MWh All year Dispatchable Standby Generation 1,000 $20-$40/kW-year $175-300/MWh All year

The resource programs are described below.

Direct load control for air conditioning . Direct control of air conditioners, by cycling or thermostat adjustment, is one of the most common demand-response programs across the country, and is most attractive in areas where elec tricity load peaks in the summer. The Pacific Northwest as a whole is still winter-peaking, but new forecasts show the region’s summer peak load growing faster than wint er peak load. PacifiCorp’s Rocky Mountain Power division and Idaho Power already face summer-peaking load. The two utilities have acquired and exercised more than 100 peak megawatts of demand response from direct control of air conditioning. Most of those 100 megawatts are outsi de the Council’s planning region, in Utah. The assumption for the portfolio model analys is is that there will be 200 megawatts of this resource in the region by 2030. Based on PacifiCorp’s experience, the resour ce is assumed to cost $60 per kilowatt a year and to be limited to 100 hours per summer.

Irrigation. PacifiCorp and Idaho Power currently are reducing irrigation load by nearly 100 megawatts through scheduling controls. Both ut ilities are in the proce ss of modifying their programs to give them more control of the resour ce, increasing the load reduction available when the utilities need it. There is significant irri gation load elsewhere in the region as well. The assumption for the portfolio model analysis is that 200 megawatts of irrigation demand response will be available by 2030. Based on PacifiCorp’s experience, this resource is assumed to cost $60 per kilowatt a year, limited to 100 hours pe r summer. Since the adoption of these assumptions for the draft plan, the Council has learned that the planned acquisition of demand response from irrigation by Idaho Powe r alone would exceed 200 megawatts.

Direct load control of sp ace heat and water heat. While there has been some experience with direct control of water heating in the region, e xperience with direct cont rol of space heating is limited. The assumption for the portfolio model analysis is 200 megawatts, at $100 per kilowatt a year for a maximum of 50 hours per winter. These assumptions are informed by the Global Energy and Brattle Group study for Bonneville. The megawatt assumption is about half the study’s estimate for residential and commercial direct-control programs when the study’s most optimistic result is extended from Bonne ville’s customers to the whole region.

Aggregators. Increasingly, aggregators facilitate demand response by acting as middlemen between utilities or system operators on the one hand and the ultimate users of electricity on theChapter 5: Demand Res ponse Sixth Power Plan

5-10 other. These aggregators are known by a variet y of titles such as “demand response service providers” for the independent system opera tors in New York and New England and “curtailment service providers” for the regional transmission organization in the Mid-Atlantic states (PJM). Aggregators could recruit demand response from loads already described here, in which case aggregators would not add to the tota l of available demand response. But in the Council’s analysis, aggregators are assumed to achieve additional demand response by recruiting
commercial and small industrial load that is not otherwise captured. This resource is assumed to be 450 megawatts. The assumed fixed costs of $70 a kilowatt per year and variable costs of $150 per megawatt-hour are based on conversations with aggregators. The resource is assumed available for a maximum of 80 hours during the winter or summer.

Interruptible contracts. Interruptible contracts offer rate discounts to customers who agree to
have their electrical service inte rrupted under defined circumstances. This is an old mechanism for reducing load in emergencies, although in so me cases it became a de-facto discount with no expectation that the util ity would ever actually interrupt serv ice. These contracts usually are arranged with industrial customers, and PacifiCo rp has about 300 megawatts of interruptible load under such contracts. The assumption for the portf olio analysis is that 450 megawatts will be available by 2030 at a fixed cost of $80 a kilowatt per year, limited to 40 hours a year. The costs of existing interruptible contracts are considered proprietary, so the Council’s cost assumption is based on conversations with aggregators.

Demand buyback. Utilities with demand-buyback programs offer to pay customers for reducing load for hours-long periods on a day-ahead basis. Earl y in the 2000-2001 energy crisis,
Portland General Electric conducted a dema nd-buyback program and had significant participation. Other utilities were developi ng similar programs, but the idea of buying back power for several hours a day wa s overtaken by high prices in a ll hours, and deals were made that bought back power for m onths rather than hours. 15 Since 2001, the most active buyback program has been PacifiCorp’s program. Buyback programs still exist elsewhere in principle, but have not been maintained in a ready-to-use state. While this option could be replaced by expanded aggregator programs, the assumption for th e Council’s portfolio m odel analysis is that demand buyback programs with customers who d eal directly with ut ilities (not through aggregators) could amount to 400 megawatts by 2 030, at fixed costs of $10 a kilowatt per year and variable costs of $150 per me gawatt-hour available all year. These cost assumptions are based on the experience of Portland General Elec tric with its Demand Exchange program in
2000-2001.

Dispatchable standby generation. This resource is composed of emergency generators in office buildings, hospitals, and othe r facilities that need electric power even when the grid is down. The generators also can be used by utilitie s to provide contingent reserves, an ancillary service. Ancillary services are not simulated in the portfolio model, but dispatchable standby generation is nevertheless a form of demand respons e that has significant potential and cannot be overlooked. Portland General Electric has pursued this resource aggressively, taking over the maintenance and testing of the gene rators in exchange for the right to dispatch them as reserves when needed. PGE had 53 megawatts of dispat chable standby generation available in early 2009, and plans to have 125 megawatts by 2012. This potential will grow over time as more facilities with emergency generatio n are built and existing facilities are brought into the program.

15 These longer-term buybacks were predominantly from Direct Service Industries (DSIs).Chapter 5: Demand Res ponse Sixth Power Plan

5-11 The Council assumes that at leas t 300 megawatts would be available in PGE’s service territory by 2030, and that the rest of the re gion will have at leas t twice as much, for a total of about 1,000 megawatts by 2030. Based on Portland General Electric’s program, cost assumptions are $20- $40 per kilowatt per year fixed cost and $175-$3 00 per megawatt-hour variable cost, available all year.

The dispatchable standby generation component is expected to be used for contingency reserves, which cannot be represented in th e regional portfolio model. The other programs were simulated in the portfolio model, with schedules based 16 on those in Table 5-3. The air conditioning and irrigation programs were treated as one program, since their costs and dispatch constraints were identical. That program, the space and water he ating program, the aggregator’s component, and the interruptible contracts compone nt were modeled similarly.

Table 5-3: Schedule of Demand Response Progr ams in the Regional Portfolio Model (MW)

2009 2011 2013 2015 2017 2019 2021 2023 2025 2027 2029 AC and Irrigation 100 200 230 260 290 320 350 380 400 400 400 Space and Water Heat 10 20 30 40 50 70 90 120 160 200 Aggregators 20 60 100 150 200 250 300 350 400 450 Interruptible Contracts 50 100 150 200 250 300 350 400 450 450
Demand Buyback 70 100 130 160 190 220 250 290 340 370 400



### Caveats for Demand Response Assumptions
While the Council regards these assumptions as reas onable for the region as a whole, each utility
service area has its own characteristics that determine the demand response available and the programs most cost-effective in that area. Further, while the allocation of the total potential to individual components is reas onable, more experience coul d well support changes in the allocation. For example, ALCOA has offered to provi de reserves as part of its proposed contract with Bonneville. This could provide from a bout 15 megawatts to over 300 megawatts of demand response, depending on how much aluminum produc tion capacity is operati ng and the level of compensation. 17 Cold-storage facilities for food ar e estimated to use about 140 average megawatts of energy in the region and could be interrupted briefly without compromising the quality and safety of food. As the region ga ins more experience the Council will revise these assumptions.



### Ongoing Analysis with the Regional Portfolio Model
The portfolio model analysis described in Chap ter 9 did not include demand response options in the “efficient frontier,” although some demand-res ponse options were included in portfolios that were quite close. The Council continues to regard demand response as a resource with

16 Because of computer run-time consider ations, the schedules were treated as ten-year blocks. The portfolio model tried various combinations of these blocks to determine which combinations appeared in portfolios on the efficient frontier (see Appendix H). 200 megawatts of air conditioni ng and irrigation were assumed adopted in all portfoliosto reflect the level of program already adopted by PacifiCorp and Idaho Power, and the 400 megawatts of demandbuyback resource was assumed adopted in all portfolios based on its very low fixed costs. The remaining resources were modeled as “optional”-- that is, the portfolio model could include them or not in trial portfolios.

17 See Appendix H for details on the range of demand response potential from this possibility.Chapter 5: Demand Res ponse Sixth Power Plan

5-12 significant potential to reduce the cost and risk of a reliable po wer system. The action plan of this program includes further work with the port folio model to better reflect and estimate the value of demand response. The action plan al so includes work to understand the potential of demand response to provide ancillary services; this latter work will need to use other approaches, since the portfolio model does not simulate the within-the-hour operation of the power system.



## Pricing Structure

The Council is not making assumptions now about the amount of demand response that might be available from pricing structures. There is no doubt that time-sens itive prices can reduce load at appropriate times, but the region does not yet appear to be rea dy for general adoption of these pricing structures. While hourly meters are b ecoming more common, most residential customers don’t yet have them, which makes time-of-day pric ing, critical-peak prici ng, peak-time rebates, and real-time prices unavailable to those customers for the time being. Many in the region are concerned that some customers will experien ce big bill increases w ith different pricing
structures. There also is the potential for double counting be tween demand-response programs and any pricing struct ure initiatives.

The Pacific Northwest Demand Response Proj ect, co-sponsored by the Council and the Regulatory Assistance Project (see Appendix H) is taking up the subjec t of pricing structures as a means of achieving demand response. In additio n, Idaho Power and Portland General Electric are launching pilot projects for ti me-sensitive electricity prices, wh ich can be expected to provide valuable experience not only for those ut ilities but for the region as a whole.



## Providing Ancillary Services with Demand Response

Demand response usually has been regarded as an alternative to generation at peak load (or at least near-peak load), that occurs a few hour s per year. Because demand response for this purpose is only needed a few hours per year, cust omers need to reduce their usage for only a few hours per year. The load that is reduced by demand response need not be year-round load, as long as the load is present during hours when system load is at or near peaks (the most familiar example is air conditioning load for summer-peaking systems).

But demand response can do more than help meet peak load. It can help provide ancillary services such as contingency reserves and regul ation and load following. Historically ancillary services have not been considered a problem in the Pacific Northwest, bu t as loads have grown, and especially as wind generation has increase d, power system planners and operators have become more concerned about ancillary services (see Chapter 12). Not all demand response can provide such services because they have differe nt requirements than meeting peak load.

Ancillary services are not simulated in the Counc il’s portfolio model so the potential value of demand response in this area will not be captured in the model’s analysis. Nevertheless, the potential cannot be ignored, and the subject should be pursued as one of the demand-response
action items.Chapter 5: Demand Res ponse Sixth Power Plan

5-13 

### Contingency Reserves
In some respects providing contingency reserves with demand response is similar to meeting peak loads with demand response. In both cases load reductions of a few hours per year are likely to meet the system need. 18

But in other respects providing contingency reserves requires somewhat different demand response than meeting peak loads. To provide contingency reserves during non-peak load hours, demand response will require reductions in end-use loads that are present in those hours. For example, residential space heat ing cannot provide reserves in the summer; residential air conditioning cannot provide reserves in the winter; but commercial lighting and residential water heating can provide contingency reserves throughout the year.



### Regulation and Load Following
Providing regulation and load following with demand response presents new requirements, compared to serving peak loads. Regulation is provided by generators that automatically respond to relatively small but quite rapid (in seconds ) variations in power system loads and generation. Load following is prov ided by larger and slower adjust ment in generator output in response to differences between the amount of pr escheduled generation and the amount of load that actually occurs. Regulation and load follo wing are needed in virtually every hour of the year, and require that generation be able to both increase and decrease.

Many customers who would be will ing to provide demand response for meeting peak loads will not be available for regulation or load followi ng. Providing regulation or load following with demand response would involve decreasing or increasing loads in virtually every hour. 19 Customers who are willing and able to decrease and increase use when the power system needs it
will be harder to recruit than those who are willin g and able only to decrease loads. Even if customers are asked only to decrease loads, many of them who could partic ipate in, for example, a 100-hour-per-year demand-response program that he lps meet peak loads, will not be able to participate in a load-following program that requires thousands of actions per year.

While demand response that can provide regulation or load following will be a subset of all possible demand response, there may well be a us eful amount. What kinds of loads make good candidates for this kind of demand response?

One example would be pumping for municipal water systems. Such systems don’t pump continuously -- they fill reservoirs from which wate r is provided to customers as needed. The schedule of pumping can be quite flexible, as long as the reservoir level remains somewhere between specified minimum and maximum levels. For such a load, the water utility could specify the total amount of pumping for the ne xt 24 hours based on its customers’ expected usage, and allow the power system to vary the pu mping over the period to help meet variation in the power system’s loads (and variation of wind generation), as long as the total daily pumping

18 Contingency reserves are only called to operate when unexpected problems make the regularly scheduled resource unavailable, which occurs infrequently. Further, utilities are required to restore re serves within 105 minutes, so that the reserves’ hours of operation per oc currence are limited. The result is that actual calls on contingency reserves are likely to be a few hours per year.

19 It may be possible to achieve an equivalent effect by a combination of loads that can make reductions when necessary together with generation th at can make reductions when necessary. One such combination could be demand response and wind machines.Chapter 5: Demand Res ponse Sixth Power Plan

5-14 requirement is satisfied. Currently, accomplis hing this degree of coordination between the power system and its customers is probably not pr actical, but with the Smart Grid’s promise of cheaper metering and communicatio n and more automated control, it could become so.

Another example is the charging load for plug-in hybrid vehicles (PHEV). Many parties have suggested this possibility, and th e general outline of the potential interaction of PHEV with the power system is common to most proposals -- vehi cle batteries together act as a large storage battery for the power system whenever they are connected to the grid -- at home, at work, or elsewhere. This aggregate battery accepts electricity when the cost of electricity is low (e.g. at night) and gives electricity back to the system when the cost is high (e.g. hot afternoons or during cold snaps). The Sm art Grid could coordinate 20 this exchange. 21

Domestic water heating is yet another example of a load that could be managed to provide regulation or load following to th e power system. In this case we have enough information to make a rough estimate of how much fl exible reserve could be available. 22 Current estimates of the region’s total number of electric water heater s run in the 3.4 million ra nge. If each of these heaters has heating elements of 4,500 watts, the total connected load is about 15,300 megawatts.
Of course water heaters are not a ll on at the same time, but load-shape estimates suggest that the total water heating load on the system ranges from about 400 megawatts to about 5,300 megawatts, depending on the season, day and hour.

In normal operation water heaters’ heating elem ents come on almost immediately when hot water is taken from the tank to heat the replacemen t (cold) water coming into the tank. But if the elements don’t come on immediately, the water in th e tank is stratified, hot at the top and cold at the bottom. Opening a hot water faucet continues to get hot wate r from the top of the tank until the original charge of hot water in the tank is gone. This means that heating the replacement water can be delayed (reducing loads) for some tim e without depriving water users of hot water. Based on the load-shape estimates cited above , the maximum available reduction ranges from about 400 megawatts to about 5,300 megawa tts, depending on when it is needed.

But to provide regulation or load followi ng, reductions aren’t sufficient -- there are
circumstances when loads also need to be increa sed. An example of such a condition is 4:00 AM during the spring runoff, when demand for electrici ty is low, river flows cannot be reduced, not much non-hydropower generation is operating, and winds are increasi ng. System operators have too much energy and few good options – they can cut hydropower generati on by increasing spill, which loses revenue and can hurt fish, or they can require wind machine operators to feather their rotors, losing both market revenue and production tax credits.

Water heating can help absorb this temporary su rplus of energy and make productive use of it. Water heating loads can be increased up to the maximum connected load, but the duration of the increase will be limited by the allowable increas e in water temperature above the normal setting. If, for example, the temperature is allowed to increase from 120 degr ees Fahrenheit to 135

20 A common assumption is that this coordination includes a requirement that the charge in the PHEV’s battery at the end of the day is sufficient to get home. Even if requirement is not met, however, PHEVs have the ability to charge their own batteries, so they are not stranded.

21 One such description of how PHEV could contribute to the power system is at the Regulatory Assistance Project’s
web site www.raponline.org under the title “Plug-In Hybrid Vehicl es, Wind Power, and the Smart Grid.”

22 More details of the potential for water heating as a source of ancillary services is in Appendix K.Chapter 5: Demand Res ponse Sixth Power Plan

5-15 degrees Fahrenheit, 3.4 million 50-gallon wate r heaters can accept 6,198 megawatt-hours of energy, store it (at the cost of roughly 24 mega watt-hours per hour higher standby losses) and return it to the system in the form of a reduc tion in hot water heating requirement in a later
hour. 23

There are other loads that have some sort of re servoir of “produc t,” a reservoir whose contents can vary within an acceptable range. The “p roduct” might be crushed rock, compressed and cooled air (in the process of air separation), st ored ice (for commercial building air conditioning), pulped wood for paper making, or the like. Th is reservoir of “product” could allow the electricity customer to tolerate variation in the ra te of electricity use to provide ancillary services to the power system, assuming that the cu stomer receives adequate compensation.

There is an industrial plant in Texas that provid es 10 megawatts of regulat ion to the Electricity Reliability Council of Texas (ERCOT) the in dependent system operator of the Texas interconnected power system. ERCOT’s rules k eep plant information c onfidential, but it is understood that the plant’s process is electroc hemical, and that its uni que situation makes it unlikely that many other plants could pr ovide regulation to the power system.

23 This increase could result from an incr ease in load of 6,198 megawatts for an hour, or an increase in load of 3,099 megawatts for two hours, etc.Sixth Northwest Conservati on and Electric Power Plan

1 

# Chapter 6: Generating Resources and Energy Storage Technologies

Summary of Key Findings ....................................................................................................... ....... 2
Introduction .................................................................................................................. ................... 3 Generating Resource Applications & Services ............................................................................... 9 Energy ........................................................................................................................ ................. 9 Firm Capacity.................................................................................................................. .......... 12 Regulation and Load-following ................................................................................................ 13
Combined Heat and Power ....................................................................................................... 14
Distributed Generation ........................................................................................................ ...... 16 Hydroelectric Power ........................................................................................................... .......... 16 Existing Hydropower System ................................................................................................... 17 Integrating Fish & Wildlife and Power Planning ................................................................. 17 New Hydropower Development ............................................................................................... 19 New Hydropower Projects .................................................................................................... 19 Upgrades to Existing Hydropower Projects .......................................................................... 19 Non-hydro Renewable Energy Resources .................................................................................... 19
Biofuel........................................................................................................................ ............... 19
Landfills ..................................................................................................................... ........... 20 Agricultural and Food Wastes .............................................................................................. 20 Waste Water Energy Recovery ............................................................................................. 21 Woody Residue ................................................................................................................. .... 21 Pulping Chemical Recovery ................................................................................................. 22
Geothermal Power Generation .................................................................................................. 22
Conventional Geothermal Power Generation ....................................................................... 23
Enhanced Geothermal Power Generation ............................................................................. 23 Marine Energy ................................................................................................................. ......... 24
Ocean Currents ................................................................................................................ ...... 24
Thermal Gradients ............................................................................................................. ... 24 Salinity Gradients............................................................................................................. ..... 24 Tidal Energy................................................................................................................... ....... 25 Wave Energy ................................................................................................................... ...... 25
Solar ......................................................................................................................... ................. 26
Photovoltaics ................................................................................................................. ........ 26
Solar Thermal Power Plants .................................................................................................. 2 7
Wind .......................................................................................................................... ................ 28 Waste Heat Energy Recovery .................................................................................................... ... 30
Fossil Fuels .................................................................................................................. ................. 31
Coal .......................................................................................................................... ................. 31
Coal-fired Steam-electric Plants ........................................................................................... 32 Coal-fired Gasification Combined-cycle Plants ................................................................... 33
Natural Gas ................................................................................................................... ............ 34 Natural Gas Supply and Price ............................................................................................... 34 Natural Gas Generating Technologies .................................................................................. 35
Petroleum ..................................................................................................................... ............. 38Chapter 6: Generating Resources and Ener gy Storage Technologies Sixth Power Plan

6-2 Petroleum Coke ................................................................................................................ ......... 38
Nuclear ....................................................................................................................... ................... 39 Energy Storage Technologies ................................................................................................... .... 40 Compressed Air Energy Storage ............................................................................................... 4 1
Flow Batteries ................................................................................................................ ........... 42 Pumped-storage Hydropower ................................................................................................... 4 2
Sodium-sulfur Batteries ....................................................................................................... ..... 43 Summary of Reference Plant Characteristics ............................................................................... 43



## SUMMARY OF KEY FINDINGS

Generating resource development will be driven by the need for reliable, economic, and lowcarbon energy supplies, supplemented as needed with firm capacity to mainta in system reliability and to provide balancing reserves to co mplement variable-output energy resources.

Economical and reliable low-car bon energy generation resources av ailable in abundance in the near-term (2010 - 2015) include “local” 1 wind and natural gas combined-cycle plants. These technologies are commercially mature, economica lly competitive and relatively easy and quick to develop. Energy from these resources costs from about $90 - $110 per megawatt-hour 2

. Other low-to-moderate carbon energy generation res ources available in the near-term, but in limited quantities include biores idue energy recovery projects, natural gas and bioresidue cogeneration, conventional geothermal, new hy dropower and energy from upgraded existing hydropower projects. These resources are commerci ally mature and in many cases economically competitive. They are, however, often small and challenging to develop. Solar photovoltaics, while commercially mature, low-carbon, easy to deve lop, and available in la rge quantity, is very expensive.

Wind power in the Northwest has relied on the ex isting surplus of firm capacity and balancing reserves. Continued wind development and other variable-output energy resources (wave power, tidal current power, and solar pho tovoltaics) will eventually requi re adding firm capacity and balancing reserves to maintain the reliable operation of the power system. Simple- and combined-cycle gas turbines, re ciprocating engine-generators, compressed air energy storage, flow batteries, pumped storage hydropower, and sodium-sulfide batter ies can provide firm capacity and balancing reserves. Fu rther analysis is needed to iden tify the best alternatives for the Northwest for these technologies, as well as transmission operation efficiencies and smart grid opportunities (see Chap ter 12 and Appendix K).

In the medium-term (2015 - 2020), remote resources could be accessed via expansions to the transmission system. These include wi nd from Montana, Alberta or Wyoming and concentrating solar power from Nevada and other Southwest areas. These resources are typically 40 to 100 percent more expensive than comparable local resources because of the transmission
investment and low transmission load factor. The “lumpiness,” capital cost, and lead time of the transmission adds investment risk to these options.

1 “Local” wind refers to wind power that does not rely on the development of high-capacity, long-distance dedicated
transmission.

2 Levelized resource costs appearing in this chapter are for 2015 service, unless otherwise indicated. A more complete discussion of resource costs, including cost estimates for years ranging from 2010 to 2030 is provided in Appendix I.Chapter 6: Generating Resources and Ener gy Storage Technologies Sixth Power Plan

6-3 Conventional coal plants are unlikely to be de veloped in the near-term because of state CO 2 performance standards and climate policy uncertain ty. Additional resources available long-term (2020 - 2030) include advanced nuclear and coal gasification combined-cycle plants. Emerging technologies such as wave power, tidal current power, enhanced geothermal, deep water wind turbines, compact nuclear plants, commercial-scale carbon seque stration, and technologies that capture carbon from steam-electric coal-fired plan ts may become commerci al during this decade.

Construction costs increased 60 to 100 percen t between 2004 and mid-2008, driven by increased commodity costs, the declining value of the dollar against overseas currencies, and market
incentives for wind and other renewable technol ogies. The weakening global economy and the difficulty in securing credit has reversed this tr end and costs are declinin g for most technologies. Future costs, however, are highly uncertain. Sign ificant risks associated with power generation include natural gas price volatility and uncerta inty (combined-cycle plants), greenhouse gas control policies (coal-fired plan ts), plant size and lead time (geothermal, nuclear, coal gasification plants, and transmission for impor ting wind or solar), and technology performance (coal gasification, advan ced nuclear plants).

Climate policies will increase the cost of fossil-fueled power ge neration in proportion to fuel carbon content and plant efficiency. Estimated in creases under the mean forecast carbon dioxide allowance prices range from about 20 percent ($18 per megawatt-hour) for gas combined-cycle plants to 40 percent ($42 per megawa tt-hour) for coal steam-electric plants. 3 While carbon dioxide separation and sequestrati on could reduce the cost of co mpliance, current estimates of the cost and performance of plants so equippe d suggest that these f eatures would not be economic compared to other resource alternatives.



## INTRODUCTION

This chapter describes the various generating and energy storage alternatives available to the Northwest to meet needs during the planning period. Additional details regarding these alternatives and assumptions regarding cost, pe rformance, and availability are provided in Appendix I.

Electricity is a high value form of energy produced from naturally occurring primary energy sources. These include the fossil fuels (coal, petroleum, and natural gas), geothermal energy, nuclear energy, solar radiation, energy from solar radiation (wind, hydropower, biomass production, ocean waves, ocean thermal gradients, ocean currents, and salinity gradients), and tidal energy.

The energy of these primary resources is capture d, converted to electricit y, and delivered to the end-user by means of energy conversion systems. An energy conversion system may include fuel extraction, fuel transportation and fuel pr ocessing, power generation, and transmission and distribution stages. Most power generation technologies are mechan ical devices that capture the energy contained in heated, pressurized or moving fl uids, and use this energy to drive an electric power generator. Exceptions incl ude fuel cells (solid-state devices that convert the chemical energy of hydrogen into electric power) and photovoltaics (solid-state devices that convert solar radiation to electric power).

3 Values are for 2015 service.Chapter 6: Generating Resources and Ener gy Storage Technologies Sixth Power Plan

6-4 Many primary forms of energy are found in the No rthwest, including various types of biofuel, coal, geothermal, hydropower, marine energy re sources, solar, and wind. Others, including natural gas, uranium, and petroleum are readily transported into the regi on. The few resources
not available in the Northwest include ocean th ermal differentials and ocean currents (both insufficient in the Northwest for practical application) and adequate direct normal solar radiation for concentrating solar thermal plants. 4

This chapter reviews all resources potentially ava ilable to meet Northwest electrical needs within the next 20 years; however, only proven resources were further evaluated for the recommended resource portfolio (Chapter 10). The Power Act re quires priority be given to resources that are cost-effective, defined as a resource that is avai lable at the estimated incremental system cost no greater than that of the least-cost similarly reliable and available alternative. 5 Since resources using reliable, commercially available technologi es can meet the region’s forecast needs over the 20-year planning period, unproven re sources, including those whose av ailability and quantity is poorly understood or that depend on immature tec hnology were not considered for the portfolio risk analysis. Certain unprove n resources, including salinity gradient energy generation, deep water wind power, wave energy, tidal currents, and enhanced geothermal have substantial Northwest potential. Actions to monitor and support development of these technologies are included in this plan.

Energy storage technologies dec ouple electricity production from consumption and can be used to shift energy from lower value to higher value periods and to provide fi rm capacity, balancing reserves, and other capac ity-related services. Storage technol ogies that have the greatest value for the Northwest are those that can provide exte nded (multi-day) energy storage, firm capacity, and balancing reserves. These include compresse d-air energy storage, flow batteries, pumped storage hydro, and sodium-sulfur batteries.

Characteristics of potential No rthwest generating resources and energy storage technologies are
summarized in Table 6-1. The far left column of Table 6-1 lists primary energy resources. The second column shows the leading energy conversion technologies. The third column lists the services available from each resource/technology combination including firm capacity for system reliability, electric energy produc tion, balancing (fast-response) cap acity for regulation and loadfollowing, shaping, cogeneration, and polygeneration (production of fuel and other products).
The fourth column contains estimates of undevel oped potential in the Northwest. In many cases the available potential is a function of cost; additi onal resource is available at additional cost.
The next column shows the earliest service da te for new resources, assuming that project development commences January 2010. Many pr oposed wind, hydropower, and other projects are at various stages of precons truction development in the Nort hwest and could be brought into service prior to the earliest service dates shown. The Reference Capacity Cost column shows the levelized fixed cost of those resources typi cally used for capacity-related services. The Reference Energy Cost column shows levelized elect ricity cost for resources primarily used for electricity production. On the far right of the table are listed the principal ri sks and other issues
associated with each resource.

4 Satellite data suggests that local areas in southweste rn Idaho and southeastern Oregon may be suitable for concentrating solar power. Further gro und data is needed to confirm this.

5 Regional Act 3.(4)(A)Chapter 6: Generating Resources and Energy Storage Technologies Sixth Power Plan6-5Table 6-1: Summary of Generating Resources and Energy Storage TechnologiesResourceLeadingTechnologyServicesEstimatedUndevelopedPotentialEarliestServiceCapacityCost($/kW-yr)6Energy Cost($/MWh)5Key IssuesRenewable ResourcesHydropowerNew projects Firm capacityEnergyLow hundreds ofMWa?2016 -- $60 and up Siting constraintsDevelopment cost & leadtimeUpgrades toexisting projectsFirm capacityEnergyBalancingLow hundreds ofMWa?ProjectspecificProject-specificProject-specificWastewatertreatment gasReciprocatingenginesFirm capacityEnergy7 - 14 MWa 2012 -- $104 Cost (smaller treatmentplants)Landfill gasReciprocatingengineFirm capacityEnergy70 MWa 2012 -- $73 Competing uses ofbiogasAnimal manureReciprocatingengineFirm capacityEnergy50 - 110 MWa 2012 -- $80 - $140 CostCompeting uses ofbiogasWoody residuesSteam-electric Firm capacityEnergyCogeneration665 MWa 2014 -- $88 - $125 CostCHP revenueReliable fuel supplyGeothermalBinaryhydrothermalFirm capacityEnergy370 MWa 2017 -- $81 Investment risk(Exploration & well fieldconfirmation)EnhancedgeothermalFirm capacityEnergyThousands ofMWa?Uncertain -- Not available Immature technologyTidal currentWater currentturbinesEnergy Low hundreds ofMWa?Uncertain -- Not available Immature technologyEnvironmental impactsCompeting uses of sitesWaveVarious buoy &overtoppingdevicesEnergy Low thousands ofMWa?Uncertain -- Not available Immature technologyCompeting uses ofseaspaceOffshore WindFloating WTG Energy Thousands ofMWa?Uncertain -- Not available Immature technologyCompeting uses ofseaspaceSolarUtility-scalePhotovoltaic arraysEnergy Abundant 2013 -- $280 CostPoor load/resourcecoincidenceAvailability and cost of62015 service except as indicated; values above $125/MWh rounded. See Appendix I for more detail.Chapter 6: Generating Resources and Energy Storage Technologies Sixth Power Plan6-6balancing servicesSolar (Nevada)Parabolic trough Firm capacityEnergy600 MWa/500kVcircuit2015 -- OR/WA $230ID $190CostLack of suitable PNWresourceAvailability and cost oftransmissionWind (Local)Wind turbinegeneratorsEnergy OR/WA - 1410MWaID - 215 MWaMT - 80 MWa2013-- OR/WA $103ID $109MT $89Availability and cost ofbalancing servicesWind (Alberta)Energy 760 MWa/+/-500kVDC Ckt2015 -- OR/WA $140Availability and cost ofbalancing servicesAvailability and cost oftransmissionWind (Montana)Energy 570 MWa/new500kV CktVia CTS Upgrade2015 -- ID $116OR/WA $150OR/WA $130Availability and cost ofbalancing servicesAvailability and cost oftransmissionWind (Wyoming)Energy 570 MWa/500kVCkt2015-- ID $121OR/WA $150Availability and cost ofbalancing servicesAvailability and cost oftransmissionWaste HeatWaste heatBottoming RankinecycleEnergy Tens to lowhundreds of MW?2014 -- $63 Suitable host facilitiesHost facility viabilityFossil FuelsCoalSteam-electric Firm capacityEnergyAbundant No CSS2017CSSUncertain-- No CSSOR/WA $108(2020)CSSMT > OR/WA viaCTS repower $140(2025)GHG policyImmature CO2separationtechnologyLack of commercial CO2sequestration facilityGasificationcombined-cycleFirm capacityEnergyBalancingPolygenerationAbundant No CSS2017CSSUncertain-- No CSSOR/WA - $118(2020)CSSMT > OR/WA viaCTS repower $140(2025)Investment riskReliabilityGHG policyLack of commercial CO2sequestration facilityPetroleum cokeGasificationcombined-cycleFirm capacityEnergyBalancingAbundant No CSS2017-- No CSSWA/OR - $120Investment riskReliabilityGHG policyChapter 6: Generating Resources and Energy Storage Technologies Sixth Power Plan6-7Polygeneration CSSUncertain(2020)CSSMT > OR/WA viaCTS repower $140(2025)Lack of commercial CO2sequestration facilityNatural gasCombined-cyclegas turbineFirm capacityEnergyBalancingCogenerationAbundant 2014 Baseloadincrement$166Duct-firingincrement$113Baseload $87Duct-firingincrement $1177Gas price volatility &uncertaintyAeroderivative gasturbineFirm capacity (faststart)BalancingCogenerationAbundant 2012 $164 $130 Gas price volatility &uncertaintyFrame gas turbine Firm capacityBalancingCogenerationAbundant 2012 $134 $140 Gas price volatility &uncertaintyHybrid intercooledgas turbineFirm capacity (faststart)BalancingCogenerationAbundant 2012 $164 $125 Gas price volatility &uncertaintyReciprocatingengineFirm capacity (faststart)EnergyBalancingCogenerationAbundant 2012 $172 $135Gas price volatility &uncertaintyNuclear FissionNuclearAdvanced lightwater reactorFirm capacityEnergyAbundant 2023 -- $108 (2025) Public acceptanceCost escalationConstruction delaysRegulatory risk“Single shaft” reliabilityriskSmall modularreactorFirm capacityEnergyCogenerationAbundant Uncertain -- Not available Immature technologyEnergy StorageElectricityCompressed airenergy storageFirm capacityBalancingDiurnal shapingUncertain NotevaluatedUncertain &site-specific-- Confirming suitablegeologyMonetizing system74,000 hours/year.Chapter 6: Generating Resources and Energy Storage Technologies Sixth Power Plan6-8benefitsFlow batteries Firm capacityBalancingDiurnal shapingNo inherent limits Uncertain Uncertain -- Immature technologyMonetizing systembenefitsPumped storagehydroFirm capacityBalancingDiurnal shapingThousands of MW 2016 $324 -- Project developmentMonetizing systembenefitsSodium-sulfurbatteriesFirm capacityBalancingDiurnal shapingNo inherent limits Uncertain -- Early commercialtechnologyMonetizing systembenefitsChapter 6: Generating Resources and Ener gy Storage Technologies Sixth Power Plan

6-9 

## GENERATING RESOURCE APPLICATIONS & SERVICES

Energy production has been the primary focus of the generating resource assessments of previous power plans because the Northwest’s hydropower system is capacity-rich and energylimited. Increasing demand for balancing reserves 8 to integrate wind power and a prospective firm-capacity shortfall in coming years has broadene d to scope of this plan to consider resource capacity as well as energy characteristics. Gene ration technologies differ in their ability to provide these services and at what cost. Capaci ty issues are further di scussed in Chapter 12.

The principal power system services of signifi cance to long-term planni ng are energy, balancing reserves, and firm capacity (the ability to contribute to meeting peak load). 9 Some power plants also provide cogeneration (also referred to as combined heat and power or CHP) or polygeneration. A cogeneration power plant simu ltaneously produces electricity and thermal energy for industrial and commercial processes or for space conditioning. In addition to providing an additional revenue stre am, cogeneration increa ses the thermal efficiency of fuel use
and can reduce the net carbon dioxi de production and other environm ental effects of electricity production. A polygeneration plant produces chemical products (fer tilizer and liquid or solid fuel, for example) in addition to electric power.



## Energy

Power plants with low variable-production cost s are run primarily to produce electric energy (baseload plants). Little can be saved by cu rtailing their operation, so they are typically dispatched to the extent that they are availabl e for operation. Because non-fuel variable costs are generally a minor element of production costs, base load units tend to be those with low (or no) fuel costs such as coal, hydropower, geothermal, bi ogas, wind, solar, and nuc lear plants. Natural gas combined-cycle plants, while using a relativel y expensive fuel, are very efficient, so they typically operate as intermediate load units, producing energy at times of higher demand and prices, but curtailed during periods of low en ergy prices. Cogeneration plants, though often using expensive fuel (natural ga s or residue biomass) , are efficient and normally have a steady thermal load, so they also operate as baseload plants.

The estimated levelized cost of electricity from new generating re sources is shown in Figures 6- 1A-C. These costs represent the revenue requirements needed to generate and deliver electricity to the wholesale delivery point (substation) of a local utility. The cost s include all costs of providing electricity to the end-us er except for distribution costs and losses. Distribution costs
and losses are credited to conservation in this plan for comparability to generating resource options.

Four elements of delivered wholes ale electricity costs are shown in the charts for each resource option: Plant costs – the cost of constructing and operating the power pl ant; Integration cost –

8 Balancing reserves provide regulation and load-following to integrate variable-output renewable energy resources. This is also referred to as system flexibility.

9 In addition to energy, seven capacity related ancillary se rvices are needed to reliably operate a power system and are therefore commercially significant. These include: regulation, load-following, spinning reserves, non-spinning reserves, supplemental or replacement reserves, vo ltage support, and black start. See Kirby, B. Ancillary Services Technical and Commercial Insights , July 2007 for additional discussion.Chapter 6: Generating Resources and Ener gy Storage Technologies Sixth Power Plan

6-10 the cost of balancing reserves for variable re sources; Transmission costs – the costs, including
cost of losses to deliver the el ectricity to the utility; and, CO 2 costs – the forecast cost of securing
carbon dioxide allowances. Further discussion of the resource cost estimates is provided in Appendix I.

Figure 6-1A shows resources that could be broug ht into service in the near-term (2010-14). These include resources with short development and construction lead times such as wind and simple-cycle gas turbines, and longer-lead time plants such as geothermal and new hydropower for which development work 10 is underway. The costs shown in the figure are for projects entering service in 2015 (in 2006 dollar values).

Figure 6-1B includes additional resources that co uld be brought into service in the mid-term period (2015-19). These include remote wind a nd solar resources that need new long-distance transmission, and technologies su ch as coal-fired steam-electric and gasification plants, needing a long time to develop and construct. Although i llustrated in the chart for comparative purposes, the coal-fired options are currently preclud ed by Montana, Oregon, and Washington carbon dioxide performance standards and the Idaho mora torium on coal-fired generation. The costs in the figure are for projects entering service in 2020 (in 2006 dollar values). The effects of forecast technological improvements and fuel prices on the relative cost of certain resources are evident in this and in Figure 6-1C. Several resource alternatives with low and stable costs that appear in Figure 6-1A have been om itted from Figure 6-1B for clarity.

Figure 6-1C shows resources that could be brought into service in the long-term period (2020- 29). Nuclear plants and commercia l-scale carbon dioxide sequestra tion facilities using depleted oil and gas fields are assumed to be availa ble by this period. Car bon dioxide sequestration facilities using depleted oil and gas fields could be loca ted in Montana, Wyoming or
Saskatchewan and accessible to co al-fired plants located in ea stern Montana via high-pressure carbon dioxide pipelines. This could offer the possibility of re powering the Colstrip Transmission System (CTS) with wind power or with coal gasificat ion plants with carbon dioxide separation (Colstrip 1 and 2 will have be en in service for 50 years by 2025). The costs shown in the figure are for projects entering service in 2025 (in 2006 dollar values). As in Figure 6-1B, low-cost resource alternatives with relatively stable costs have been omitted for clarity, as have more costly versions of co mpeting technologies (e.g., sub-critical coal steam technology has been omitted in fa vor of ultra-supercri tical technology, for example). These are fully described in Appendix I.

Although the levelized energy costs shown in the figures are often used for initial comparison of resources, evaluating resources for acquisition must consider the needs and characteristics of the system using the resource, the capacity and en ergy services provided by the resource, and the costs and risks incurred acquisiti on and operation of the resource. These factors are considered in the resource strategy (Chapters 9 and 10).

10 “Development” is used in this chapter as the process of preparing to construct a power plant, including site selection; feasibility assessment; environmental, geotechn ical and resource assessment; permitting; and preliminary engineering. Project development is generally akin to the resource optioning process referred to elsewhere in the plan.Chapter 6: Generating Resources and Ener gy Storage Technologies Sixth Power Plan

6-11 Figure 6-1A: Levelized Lifecycle Electricity Co st for Generating Options Available in the Near-term (2010-14) 11

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11 Assumptions: 2015 service, investo r-owned utility financing, medium fuel price forecast, wholesale delivery point. CO 2 allowance costs at the mean values of the portfo lio analysis. Incentives ex cluded, except accelerated depreciation. Actual project costs may differ because of site-speci fic conditions and differen t financing and timing.

12 Assumptions as in Figure 6.1A except 2020 service.Chapter 6: Generating Resources and Ener gy Storage Technologies Sixth Power Plan

6-12 Figure 6-1C: Levelized Lifecycle Electricity Co st for Generating Options Available in the Longer-term (2020-25) 13

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## Firm Capacity

With the exception of wind and other variable-output resources, most power plants provide firm capacity to meet peak load a nd provide contingency reserves. 14 In general, non-variable plants can provide capacity up to their net installed capac ity less an allowance for forced (unscheduled) outages, though in some cases, contractual, fu el, permitting, and environmental conditions may limit the firm capacity contribution.

Some resources are developed pr imarily to provide firm capacity. Because they are operated infrequently, variable cost is less important than fixed costs. Also, un its intended for peaking service may need rapid startup a nd load-following ability to a void displacing generation with a lower variable cost. A comparison of the fixed co sts of several resources typically developed for capacity is provided in Figure 6-2. In the case of the combined-cycle opt ion, the cost shown is the incremental cost of duct firing. Duct firi ng is an inexpensive option for increasing plant output (though at some sacrifice of efficiency) and is usually pr ovided on combined-cycle units. But duct firing capability is limited and other capacity resources are sometimes needed.

As with levelized energy cost estimates, the leve lized capacity cost estimat es of Figure 6-2 is not the sole criterion for choosing among these optio ns. The technologies shown have different attributes, possibly leading to different choices depending on needs. Aeroderivative and intercooled gas turbines and recipr ocating engines, for example, ha ve very rapid start times (less than 10 minutes), allowing them to provide “spi nning” reserve, even when shut down. Duct firing and intercooled gas turbines require cooling water, whereas other types of simple-cycle gas

13 Assumptions as in Figure 6.1A except 2025 service.

14 Capacity held for use in case of a contingency event such as unplanned loss of generation.Chapter 6: Generating Resources and Ener gy Storage Technologies Sixth Power Plan

6-13 turbine and reciprocating units requi re very little water, a factor of importance in arid regions. Reciprocating engines and intercooled gas turbines have attr active “turndown” characteristics, meaning that plant operating efficiency remain s high even at very low loading. Moreover, anticipated operating conditions can affect fixed costs. Gas tu rbines, if located in a nonattainment area may need expensive air emission controls.

Figure 6-2: Fixed Cost of Commercia lly-available Firm Capacity Options 15

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## Regulation and Load-following

The large amount of wind power added to the No rthwest’s power system has increased demand for regulation and load-following services. Regu lation is the continuous balancing of generation to load on a second-to-second basis and is typi cally supplied by fast-response generating units equipped with automatic generati on control. Hydropower units are normally used to provide regulation in the Northwest. Though wind power at low pene tration does not significantly
increase the net second-to-sec ond variability of load and gene ration, incremental variation is introduced as wind penetration increases. Ho wever, the incremental demand for regulation introduced by wind, even at high penetration le vels is relatively small compared to the incremental increase in load-following requirements.

Load-following services make up the difference between scheduled (forecasted) generation and actual load. Load-following is currently provided by operating capacity set to provide either upward (incremental) regulation (“Inc”) or dow nward (decremental) regulation (“Dec”). The need to prepare for unpredicted rapid upward a nd downward ramps in wind output is increasing demand for load-following capability.

15 2015 service.Chapter 6: Generating Resources and Ener gy Storage Technologies Sixth Power Plan

6-14 A related service is shaping. Shaping involves the shifting of energy from low value off-peak hours to higher value on-peak hours on a diurnal or multi-day basis. Shaping can also be used to level load on transmission lines serving remo te renewable resource areas, thereby reducing
incremental transmission costs.

Resources suitable for providing re gulation and load-following services have rapid and flexible response capability, good turndown characteristic s and, ideally, near-market operating costs (to reduce economic losses during load-following opera tion). Other desirable attributes include siting flexibility and low part-load emissions . Among new generating resources, the most attractive options for supplying regulation and lo ad-following services are combined-cycle gas turbines, aeroderivative and interc ooled simple-cycle gas turbines , and reciprocating engines. Long-duration storage technologi es including pumped-storage hydro, compressed-air energy storage, flow batteries, and sodium-sul fur batteries offer similar capability.

Because the balancing capability of the existing system may need to be augmented in future years to support expansion of wind and other variable resources, the cost and value of the various options augmenting balancing capability for the No rthwest’s system should be explored. Action GEN-6 calls for this effort, which should consider combined-cycle plants, gas turbine generators, reciprocating engines, pumped-storage hydro, co mpressed-air energy storage, flow batteries, sodium-sulfur batteries, and demand-side options.



## Combined Heat and Power

Combined heat and power (CHP or cogeneration) plants produce both electricity and thermal or mechanical energy for industrial processes, spac e conditioning or hot water. The fundamental attribute of CHP is higher thermodynamic effici ency compared to the separate production of electricity and thermal or mechanical services. Improved efficiency is achieved through higher initial temperatures and pressu res and by use of otherwise wa sted thermal energy. Typical
benefits of CHP include a net reduction in cost, carbon dioxide, and other environmental impacts; improved economic viability of the hos t facility; improved system reliability; and
reduced transmission and di stribution-system costs.

CHP includes diverse combinations of fuel, tec hnologies, and applications , making it difficult to characterize a definitive CHP pr oject. Fuel used for CHP incl udes waste heat from industrial equipment and processes, natural gas, wood residue, biogas, and spent pulping liquor. Technologies include gas turbine ge nerators, combined-cycle power plants, steam-electric plants, and reciprocating-engine generator sets. Several examples of the expected cost of resources and technologies configured for CHP are descri bed in this Chapter and in Appendix I.

About 3,970 megawatts of CHP is installed in th e Northwest. About 1,790 megawatts of this capacity is industrial CHP, closely integrated with the host facility and sized to the thermal load. The remaining 2,180 megawatts are u tility-scale combined-cycle plan ts where steam is extracted
to serve an “over-the-fence” thermal load. Th e operation of industrial CHP is generally determined by thermal demand (i.e., the operation of the thermal host), whereas the operation of utility-scale combined-cycle CHP is largely dete rmined by fuel and electri city prices. Fifteen CHP plants, totaling 143 megawatts of capacity, ha ve been constructed in the Northwest since
the release of the Fifth Power Plan in 2004. All of these new plants are industrial CHP and most are fueled by bio-residue.Chapter 6: Generating Resources and Ener gy Storage Technologies Sixth Power Plan

6-15 The greatest near-term CHP potential in the Northw est is at energy-intens ive industrial facilities and commercial facilities that have large spa ce conditioning and hot water load. While technical potential exists in the commercial and residentia l sectors, these tend not to be cost-effective given the current technology. A growing CHP application is ener gy recovery from agricultural and other bio-residue where the reject heat of th e generating unit is used to maintain the wastedigester operating temperatures.

A 2004 assessment 16 identified 14,425 megawatts of tec hnical CHP potential for Idaho, Oregon, and Washington. 17 Under “business-as-usual” assumpti ons (little improvement in technology, no incentives, and standby charges) the economic pot ential through 2025 was es timated to be about 1,030 average megawatts of energy. No applications using woody biomass residue were considered, nor were any applic ations involving capturing waste energy such as gas pipeline compressor stations, cement kilns or metal reme lt furnaces. These are promising applications and this estimate of economic potential may be low because of these omissions.

Unfortunately, the full benefits of CHP are rare ly seen by the individua l parties (utility, host facility, developer) involved in the decision to develop CHP. Ma ny of the barriers to CHP stem from these differing perspectives and include:

• The required return on investment of the host facility is often higher than that of a utility.

• Unless participating as an equity partner, th e utility sees no return, and a loss of load.

• Limited capital and competing investment opportunities often constrain the host facility’s ability to develop CHP.

• Energy savings benefitting the host facility ma y not be worth the hassle of installing and operating a CHP plant.

• Difficulty establishing a guaranteed fu el supply for wood residue plants.

• Uncertainties regarding the long-term economic viability of the host facility.

• The location value of CHP is often not re flected in electric ity buy-back prices.

• The relative complexity of permitting and environmental compliance for small plants.

Actions to help resolve these issues were identified in the Fifth Power Plan. These remain valid
and include:

• Routine surveys to identify CHP and small- scale renewable energy resource development opportunities.

16 Energy and Environmental Analysis, Inc. Combined Heat and Power in the Pacific Northwest: Market
Assessment , B-REP-04-5427-004. July 2004.

17 CHP opportunities in Montana were not assessed in the Energy and Environmental Analysis study.Chapter 6: Generating Resources and Ener gy Storage Technologies Sixth Power Plan

6-16 • Resource evaluation criteria that fully re flects CHP costs and benefits, including the value of energy, capacity, and ancillary serv ices, avoided transmi ssion and distribution costs, and losses and environmental effects.

• Eliminating disincentives to utility acquisition of power from customer-side projects such as the inability of investor-own ed utilities to receive a return on investment in generation owned or operated by others.

• Uniform interconnection agreemen ts and technical standards.

• Equitable standby tariffs.

• Provisions to allow the sale of excess cust omer-generated power through the utility’s transmission and distribution system.



## Distributed Generation

Distributed generation is located at or near electrical load. Distributed generation can provide: standby power for critical load; regulation of voltage or freq uency beyond grid standards; cogeneration; local voltage support; an alternat ive to expanding transmission or distribution capacity; service to remote load; peak shaving to reduce demand charges; and an alternative source of supply for times of high power prices or system islanding. Distributed energy storage technologies can provide many of the same serv ices and emerging “smart grid” controls can synchronize the operation of numero us individual units to create a virtual large-scale storage facility. The modularity and small-scale of distributed technologies may lead to rapid technological development and cost reduction.

Distributed generation installati ons are smaller than central-sta tion plants, ranging from tens of kilowatts to about 50 megawatts in capacity. The benefits of distributed generation can best be secured with technologies that are flexible in location and sizing such as small gas-turbine generators, reciprocating-engi ne generators, boiler-steam turbines, solar photovoltaics, microturbines, and fuel cells . However, distributed gene ration applications are often uneconomic sources of bulk power compared to central-station generation because of the higher cost of equipment, operation and maintenance, fuel, and their lower thermodynamic efficiency. Still, distributed generation can be an attractiv e alternative for all the reasons listed earlier.



## HYDROELECTRIC POWER

The mountains of the Pacific Northwest and Br itish Columbia experi ence heavy precipitation, much of which falls as snow, producing large vol umes of annual runoff that create the great hydroelectric power resource for th e region. The theoretical potent ial has been estimated to be about 68,000 megawatts of capacity and 40,000 av erage megawatts of energy. Nearly 33,000 megawatts of this potential capacity has been developed at about 360 projects. Though the remaining theoretical hydroelectric power potential is large, most economically and environmentally feasible sites have been deve loped. The remaining opportunities are, for the most part, small-scale.Chapter 6: Generating Resources and Ener gy Storage Technologies Sixth Power Plan

6-17 Hydroelectric power is by far the most important generating resource in the Pacific Northwest, providing about two-thirds of the generating capacity and about three-quarters of electric energy on average. The annual average runoff volume, as measured at The Dalles Dam, is 134 million acre-feet but it can range from a low of 78 million acre-feet to a high of 193 million acre-feet. The combined useable storage in U.S. and Canadi an reservoirs is only 42 million acre-feet. This means that the system has limited capability to reshape river flows to yield energy better matching the seasonal electricity demand. The P acific Northwest is a wi nter-peaking region, yet river flows are highest in spring (during the snow melt) when electricity demand is generally the lowest. Because of this, the re gion has historically planned it s resource acquisitions based on critical hydro conditions, th e historical water year 18 with the lowest runoff volume over the winter-peak demand period. Under those conditi ons, the hydroelectric system produces about 11,800 average megawatts of energy. On averag e, it produces nearly 16,000 average megawatts of energy, and in the wettest years it can produce over 19,000 average megawatts. For perspective, the annual average regional demand is about 22,000 average megawatts. In order to reflect the important variabili ty of hydroelectric production as water conditions change, the Council’s analysis uses a 70-year water record in its analysis.



## Existing Hydropower System

The current hydroelectric system has a capacity of about 33,000 megawatts, but it operates at about a 50 percent annual capacity factor because of limited wa ter supply and storage. The Northwest’s power supply must be sufficien t to accommodate increased demand during a sustained cold snap, heat wave or the temporary loss of a generating resour ce. The hydroelectric system provides up to 24,000 megawatts of sustaina ble peaking capacity for the six highest load hours of a day over a consecutive three-day period.

These assumptions for the annual and hourly capabi lity of the hydroelectri c system are sensitive to fish and wildlife operations, which have changed in the past and could change in the future.
There remain a number of uncertainties surround ing these operations, which could have both positive and negative effects. For example, sp illway weirs offer the potential to reduce bypass spill while providing the same or better passage su rvival. Climate change has the potential to alter river flows, which affect both power pr oduction and fish survival. Dam removal or operating reservoirs at lower elevations would further reduc e power production.

For the Sixth Power Plan, hydroelectric system capa bility is based on fish and wildlife operations specified in the 2008 biologica l opinion. How climate change might affect hydroelectric generation and its impact on the re source strategy is examined via scenario analysis. However, it should be noted that the range of potential change s to hydroelectric generati on is relatively small compared to other planning uncertainties.



### Integrating Fish & Wild life and Power Planning
The Power Act requires that the Council’s power plan and Bonneville’s resource acquisition program assure that the region has sufficien t generating resources on hand to serve energy

18 The water year or hydrologic year is normally defined by the USGS from the beginning of October through the end of September and denoted by the calendar year of the final nine months. The water year of the Columbia River system, however, is modeled from the beginning of September (beginning of operation for reservoir refill) through the end of August.Chapter 6: Generating Resources and Ener gy Storage Technologies Sixth Power Plan

6-18 demand and to accommodate system operati ons to benefit fish and wildlife. 19 The Act requires the Council to update its fish and wildlife progr am before revising the power plan, and the amended fish and wildlife program is part of th e power plan. The plan then sets forth “a general scheme for implementing conservation measur es and developing resources” with “due consideration” for, among other things, “prote ction, mitigation, and enhancement of fish and wildlife and related spawning ground s and habitat, including suffici ent quantities and qualities of flows for successful migration, survival and propagation of anadromous fish.” 20

On average, fish and wildlife operations reduce hydroelectric generation by about 1,200 average megawatts relative to operation with no constraints for fish and wildlife. 21 This energy loss represents about 10 percent of the hydroele ctric system’s firm generating capability. 22

Bonneville estimates its total fina ncial obligation for the fish and wildlife program to be between $750 to $900 million per year, combining ordinary and capital expenditures, power purchases, and foregone revenues associated with opera tions to benefit fish and wildlife.

These impacts would definitely affect the ade quacy, efficiency, economy, and reliability of the power system if they had been implemented over a short time. However, this has not been the case. Since 1980, the region has periodically am ended fish and wildlife related hydroelectric system operations and, in each case, the power syst em has had time to adapt to these incremental changes. The Council’s current assessment 23 indicates that the re gional power supply can reliably provide actions specified to benefit fi sh and wildlife (and absorb the cost of those actions) while maintaining an adequate, efficient, economic, and reliable energy supply. This is so even though the hydroelectric operations for fish and wildlife have a sizeable impact on power generation and cost. The power system has a ddressed this impact by ac quiring conservation and generating resources, by deve loping resource adequacy st andards, and by implementing strategies to minimize power system emergenc ies and events that might compromise fish operations.

The Council recognizes the need to better identify and analyze long-term uncertainties that affect all elements of fish and power operations. In the action plan, the C ouncil proposes creating a public forum that would bring together power pla nners and fish and wildlife managers to explore ways to address these uncertainties. Long-te rm planning issues include climate change, alternative fish and wildlife operations, modi fications to treaties a ffecting the hydroelectric system, and the integration of variable-output re sources, in particular how they affect system flexibility and capacity. The fo rum would provide an opportunity to identify syne rgies that may exist between power and fish operations and explore ways of taking advantage of those
situations.

19 For more information please see Appendix M: Fish and Wildlife Interactions.

20 Northwest Power Act, Sections 4(e)(2), (3)(F), 4(h)(2)

21 The comparison study, which includes no actions for fish and wildlife, is represented by hydroelectric operations prior to 1980.

22 Firm hydroelectric generating capability is about 11,900 average megawatts (2007 Bonneville White Book) and is based on the critical hydro year, which is currently defined to be the 1937 historical water year.

23 See http://www.nwcouncil.org/en ergy/resource/Adequacy%20Assessment%20Final.doc

.Chapter 6: Generating Resources and Ener gy Storage Technologies Sixth Power Plan

6-19 

## New Hydropower Development

New Hydropower Projects
Though the remaining theoretical hy droelectric power potential is large, most economically and environmentally feasible capacity appears to have been deve loped. The remaining opportunities for new projects are, for the most part, sma ll-scale. Among these are: adding generating equipment to irrigation, flood control, and othe r non-power water projects ; adding generation to existing hydropower power projects with surplus stream flow; and a few projects at undeveloped sites. A comprehensive assessment of new hydr opower potential has not been attempted by the
Council since the Fourth Power Plan. In that plan, the Council estimated that about 480 megawatts of additional hydropower capacity was available for deve lopment at costs of 9.0 cents per kilowatt-hour or less. This capacity could produce a bout 200 megawatts of energy on average. Few projects have been developed in the intervening years, an d it is likely that the Fourth Power Plan estimate remains represen tative. Hydropower development costs are sensitive to project conf iguration, size, and site characterist ics. A review of recent projects shows costs ranging from $65 to over $200 per mega watt-hour and a weighted average cost for committed and completed projects of $88 per megawatt-hour. Demand for low-carbon resources and resources qualifying for stat e renewable portfolio standard s has increased interest in hydropower development, and the Council recomme nds that current efforts to reassess new hydropower potential be continued to improve understanding of the current cost and potential of
the resource.



### Upgrades to Existing Hydropower Projects
Renovations to restore the original capacity and energy production of existing hydropower projects, and upgrades to yield additional capacit y and energy are often much less costly than developing new projects. Most ex isting projects date from a time when the value of electricity was lower and equipment efficiency less than now, and it is often feasible to implement upgrades such as advanced turbines, generator rewinds, and spillway gate calibration and seal improvement. Even a slight improvement in equi pment efficiency at a large project can yield significant energy. The last comprehensive assessment of regional hydropower upgrade potential was completed more than 20 years ago and many renovations and upgrades have been completed in the intervening years. Much like end-use efficiency, improved technology and higher electricity values are likely to have increased th e undeveloped potential even as renovations and upgrades have been completed. Informal surveys suggest that several hundred average megawatts or more are potentially av ailable from renovations and upgrades. The Council recommends that a comprehensive asse ssment of hydropower upgrade potential be undertaken to gain a better understanding of the cost and potential of this resource.



## NON-HYDRO RENEWABLE ENERGY RESOURCES

Biofuel

Biofuel includes combustible organic residue from producing and consuming food, fiber, and
materials and fuel from dedica ted energy crops. Northwest bio -residue includes woody residue (forest, logging, and mill residue and the biogeni c components of municipal solid waste), spent pulping liquor, agricultural field residue, animal manure, food processing residue, landfill gas, and wastewater treatment plant digester gas. Hybrid poplar plantations have the greatestChapter 6: Generating Resources and Ener gy Storage Technologies Sixth Power Plan

6-20 potential for dedicated bio-energy production for the electrical sector in the Northwest, but historically have had greate r fiber than fuel value.



### Landfills
The anaerobic decomposition of organic ma tter from landfills produces a low-grade (~450 Btu/scf) combustible gas that largely consists of methane and carbon dioxide. Gas production usually begins one or two years following waste em placement and may last for several decades. The gas is collected and flared for safety r easons and to reduce its greenhouse gas potential. 24 Increasingly, the gas is used dire ctly as a low-grade fuel, upgraded to pipeline-quality gas, or for on-site power generation. A typical power genera tion facility consists of gas cleanup equipment and one or more reciprocating engine-generator sets. A common business model is third-party development of the gas cleanup and power genera tion facilities with pur chase of the raw gas from the landfill operator.

Seven landfill gas recovery proj ects totaling 30 megawatts of cap acity are in operation in the Northwest. The estimated feasible undeveloped power generation potential in the Northwest is about 70 average megawatts, representing about 80 megawatts of installe d capacity. Because several landfill operators are considering injecti ng the upgraded gas into the natural gas system, a portion of this potential is unlik ely to be available for power generation. The reference 3- megawatt project would operate as a must-run ba seload project and produce electricity at an estimated cost of $73 per megawatt- hour. Specific projects will vary in cost due to economies of scale, gas quality, and gas production rates. Barriers to developing landfill gas for power generation include competing uses of the gas, low financial incentives 25 , and cost, especially for
smaller landfills.



### Agricultural and Food Wastes
A combustible gas (largely consisting of methane and carbon dioxide) produced by anaerobic digestion of animal manure, food waste, and sim ilar biogenic organic material can be used to generate power. A typical animal manure or food waste energy-recovery plant uses enclosed slurry-fed anaerobic digesters fo r gas production and reciprocati ng engine generators for power generation. Heat recovered from th e engine-generator is used to maintain digester temperature and dry the residual fiber for animal bedding or soil amendment. These projects provide mustrun, baseload, carbon-neutral elec tricity from an otherwise wasted resource. The most economically feasible facilities for installing energy r ecovery are large-scale confined animal feeding operations including dairie s, swine and poultry facilities using slurry manure handling. European dry fermentation tec hnology, currently bei ng introduced to North America, could broaden energy recovery to feedlots and ot her operations using dry manure handling.

At least eight large-scal e (0.5 megawatts and large r) animal manure energy recovery projects and one food-processing residue project totaling about 13 megawatts are known to be in operation or
under construction in the Northwest. The undevel oped potential, primarily at large-scale dairy operations, is estimated to be 50 to 110 aver age megawatts. Additional potential might be secured through cooperativ e facilities serving sm aller dairy or food processing operations. Power generation costs vary widely and are sensitive to project size and the type of digester. The

24 Methane has about 21 times the greenhouse warming poten tial than the carbon dioxide product of its combustion.

25 Biogas power generation facilities receive a federal produc tion tax credit of about $10 per megawatt-hour for the first ten years of operation - one-hal f the credit received by wind projects.Chapter 6: Generating Resources and Ener gy Storage Technologies Sixth Power Plan

6-21 reference cost of elec tricity is $88/megawatt-hour. Cost s might range from $80 per megawatthour for a large 2.5 megawatt project (~16,000 head of cattle) to about $139 per megawatt-hour for a 450 kilowatt project (~ 2,900 head). Cost and collecting a sufficien t supply of manure or other agricultural waste to suppor t economically feasible projects are the biggest obstacles to growth. Aggregating sufficient biomass for an ec onomically-sized plant, and cost in general, particularly for smaller facilities, are the prim ary barriers to the grow th of food waste as a

resource.



### Waste Water Energy Recovery
In many wastewater treatment fac ilities, sludge is processed in an aerobic digesters that produce a moderate quality (600 - 650 Btu/kWh) combustib le biogas consisting largely of methane and carbon dioxide. Anaerobic digesters require additional heat for optimal operation, and the common method of disposing of the bi ogas is to use it as a fuel to ma intain digester temperature. Surplus is flared. A more productive alternativ e is to clean the biogas to use as fuel for a cogeneration plant where the heat from the gene rating unit is used to maintain digester temperature. Reciprocating engines are typically used for this application.

Nineteen wastewater treatment energy recovery projects totaling 22 megawatts are in operation or under construction in the Northwest. Though an estimate of the remaining regional potential was not located, a 2005 assessment prepared for the Oregon Energy Trust estimated 2 megawatts to 4 megawatts of undeveloped near-term potential for Oregon. Extrapolating this estimate to the region based on population suggests a re maining undeveloped near-term potential of 7 megawatts to 14 megawatts.

The reference plant is an 850-kilowatt reciproc ating engine generator fueled by gas from the anaerobic digesters of a wastewater treatment plant. Reject engine heat is captured and used to maintain optimal digester temperatures. The re ference cost of electr icity is $104 per megawatthour with the plant operating in baseload mode (seasonal fluctuations may occur due to wastewater treatment plant load ing). Capacity, site conditions, financing, and incentives can
lead to wide variation in co st. Electricity production costs might range from about $85 per megawatt-hour for larger (1 - 2 megawatts) insta llations to $120 for sma ller installations. The electricity is typically used to offset treatment plant load so electricity production costs compete with retail rates. Cost for smaller treatment plants is the primary barrier to fully developing the remaining potential.



### Woody Residue
The largest source of woody residue in the Northw est has been the forest products industry. Currently, there are 23 projects (with 283 megawatts of capacit y) using woody residue as a primary fuel operating in the Northwest, a slight increase since the Fifth Power Plan. Surveys indicate that nearly all woody resi due produced in the forest products sector are used for fuel or other purposes. Some undeveloped potential is available by separating the biogenic material from municipal solid waste, but the major new potential is forest thinning residue from ecosystem recovery and wildfire hazard reductio n efforts, and from more intensively managed commercial timberlands. This additional woody re sidue could provide about 90 TBtu of fuel energy annually on a reliable, sustained basis. Its price will vary depending on the source, alternative uses, and prevailing economic conditi ons; but it is expected to average about $3.00 per million Btu in the near-term. Expected introduction of specia lized collection andChapter 6: Generating Resources and Ener gy Storage Technologies Sixth Power Plan

6-22 transportation equipment for bulk lo w-density fuel should result in an annual average real price reduction, estimated to be 1 per cent over the period of the plan.

Conventional steam-electric plants with or without CHP will be the chief technology for electricity generation using wood re sidue in the near term. A su stained annual region-wide fuel supply of 90 TBtu is sufficient to generate about 665 average megawa tts using conventional technology. Modular biogasification plants are under development a nd may be introduced within the next several years. Modular units would ope n the possibility of “bringing the plant to the fuel” thereby expanding the pot ential fuel supply, reducing fu el transportation costs and improving the economics of plant operation.

Two reference plants were characterized: one representing favorable development conditions resulting in relatively low power cost, and a second representing longer-t erm marginal conditions and consequent higher power costs. Favorable development factors that could reduce project costs include the availability of refurbished eq uipment, sources of low-cost mill or urban wood residue, CHP revenue, a brownfield site with esta blished infrastructure, low-cost financing, and
financial incentives. These factors could resu lt in power production co sts of $88 per megawatthour, or less, within the competitive ra nge for new generating resources.

The longer-term marginal plant is a 25 mega watt stand-alone unit using conventional steamelectric technology, locate d at a greenfield site and operati ng primarily on forest thinning residue. This plant would produce electricity at $125 per megawatt-hour. Capital and fuel costs are both major components of the energy cost.

The principal barriers to deve loping woody biomass plants include high capital and fuel costs, the availability of CHP load, and ensuring an adequate, stable, and economical fuel supply.



### Pulping Chemical Recovery
Chemical recovery boilers reco ver the chemicals from spent pul ping liquor. Lignins and other combustible materials in the spen t liquor create the fuel. Rec overy boilers--usually augmented by power boilers fired by wood residue, natural gas or other fuel--suppl y steam to the pulping process. Greater efficiency is possible by produ cing the steam at high pr essure and extracting it at the desired pressures from a steam-turbine generator. When the Fourth Power Plan was prepared, eight of the 19 mills then operat ing in the Northwest were not equipped for cogeneration. Estimates prepared for that pl an indicated that an additional 280 average megawatts of electric power could be produced by installing cogeneration equipment at recovery
boilers without it. Mills have cl osed since then and upgrades have been undertaken at several of the remaining plants, including the recent add ition of a 55-megawatt generating plant at the Simpson Tacoma Kraft mill. The remaining Nort hwest potential has not been recently assessed. Limited capital availability, short pay-back peri ods, and the uncertain economic conditions in the industry typically constrain development.



## Geothermal Power Generation

The crustal heat of the earth, produced primarily by the decay of natura lly-occurring radioactive isotopes, may be used for power generation. C onventional hydrothermal geothermal electricity generation requires the coincidental presence of fractur ed or highly porous ro ck at temperatures
of about 300 o Fahrenheit or higher and wa ter at depths of about 10,000 feet or less. The mostChapter 6: Generating Resources and Ener gy Storage Technologies Sixth Power Plan

6-23 promising Northwest geologic structure for hydr othermal generation is the basin and range province of southeastern Oregon a nd southern Idaho. Here, natura l circulation within vertical faults brings hot fluid toward the surface. Ba sin and range geothermal resources have been developed for generation in Nevada, Utah, and California, and recently in Idaho. The 13- megawatt Raft River project in Idaho is the fi rst commercial geothermal power plant in the Northwest. Earlier models of the geology of th e Cascades Mountains suggested the presence of large geothermal potential. More recent resear ch suggests that while local hydrothermal systems may exist in the Cascades, geothermal potential fo r generation outside of these local systems is limited or absent. Moreover, development of much of the Cascades potential would be precluded by land-use constraint s. Newberry Volcano (Oregon) and Glass Mountain (California) are the only Cascades structures offering geothe rmal potential not largely precluded by existing land use. These structures may be capable of supporting several hundred megawatts of geothermal generation.



### Conventional Geothermal Power Generation
Depending on resource temperatur e, flashed-steam or binary-c ycle geothermal technologies could be used with the liquid-dominated hydrothe rmal resources of the Pacific Northwest. A preference for binary-cycle or heat-pump technology is emerging because of modularity, applicability to lower temperature geothermal re sources, and the environmental advantages of a closed geothermal-fluid cycle. In binary plan ts, the geothermal fluid is brought to the surface using wells and passed through a heat exchanger wh ere the energy is transferred to a low boiling point fluid. The vaporized low boi ling point fluid is used to dr ive a turbine generator, then condensed and returned to the heat exchanger. Th e cooled geothermal fluid is re-injected to the geothermal reservoir. This technology operates as a baseload resource. Flashed steam plants typically release a small amount of naturally occurring carbon di oxide from the geothermal fluid, whereas the closed-cycle binary plants releas e no carbon dioxide. The reference geothermal plant is a binary-cycle plant consisting of th ree 13-megawatt units. The estimated cost of electricity from this plant is $81 per megawatt- hour--among the lowest-cost generating resources identified in this plan.

A recent U.S. Geological Survey assessment 26 yielded a mean total Northwest hydrothermal electricity generating potential of 1,369 average megawatts. Ho wever, geothermal development has historically been cons trained by high-risk, low-succe ss exploration and well field confirmation. Using historical Nevada development rates as gui dance, the Council has adopted a provisional estimate of 416 megawatts of develo pable hydrothermal resource for the period of the plan. This would yield about 375 average megawatts of energy. These assumptions should
be revisited at the biennial asse ssment of the Sixth Power Plan.



### Enhanced Geothermal Power Generation
The natural presence of the high-temperature pe rmeable rock and fluid conditions required for conventional geothermal plants at feasible dr illing depths is uncommon. Much more common are high-temperature, but insufficiently permeable , formations. Enhanced geothermal systems (EGS) 27 create the necessary permeability by fracturi ng or other means. EGS technology is one

26 United States Geological Survey. Assessment of Moderate- and High-Temperature Geothermal Resources of the
United States , 2008.

27 Also known as engineered geothermal systems.Chapter 6: Generating Resources and Ener gy Storage Technologies Sixth Power Plan

6-24 of several emerging geothermal technologies 28 that could vastly increase the developable geothermal resource. A 2004 MIT a ssessment of geothermal potential 29 identified three areas of special EGS interest in the Northwest. Two (O regon Cascades and Snake River Plain) are unique to the Northwest. The USGS study identified 104,000 average megawatts of EGS potential at a 95 percent confidence leve l in the four Northwest states. Because EGS technology has not been commercially proven, it is not included among the re sources evaluated for the portfolio of this plan. Because of its potential, the Council encour ages Northwest utilities to support efforts to develop and demonstrate EGS technology.



## Marine Energy

Ocean Currents
The kinetic energy of flowing water can be used to generate electricity by water-current turbines operating on a principal similar to wind turbines. Conceptual designs and prototype machines have been developed and an array of current turbin es is being installed in New York City’s East River (a tidal current rather than an ocean curr ent application). Turbine energy yield is very sensitive to current velocity and little electric al potential is available from the weak and illdefined currents off the Northwest coast.



### Thermal Gradients
An ocean thermal energy conversion (OTEC) power plant extracts energy from the temperature difference that may exist between surface waters a nd waters at depths of several thousand feet. OTEC technology requires a temperature differen tial of about 20 degrees Celsius (36 degrees Fahrenheit). Temperature differentials of th is magnitude are limited to tropical regions extending to 25 to 30 degrees of latitude. Ocean thermal temperature differentials in the Northwest range from 0 to 12 degrees Celsius (0 - 20 degrees Fahrenheit ,) precluding of OTEC technology.



### Salinity Gradients
Energy is released when fresh and saline wate r are mixed. Conceptually, the energy potential created by fresh water streams discharging to salt water bodies can be conv erted to electricity. Concepts include osmotic hydro turbines, dilytic batteries, vapor pressure turbines, and polymeric salinity gradient engines. Development of salinity gradient gene ration is underway in Europe with a focus on osmotic technology. The Norwegian utility Statkr aft has completed a 4 megawatt prototype osmotic hydro turbine power plant near Oslo with the intention of developing a commercial-scale plant by 2015. A key to commercia lization is reduc ing the cost
of the osmotic membrane. Because the theore tical resource potential in the Northwest is substantial, salinity gradient technology should be monitored and an assessment of Northwest potential undertaken when the characteristics and operating requirements of commercial units
become better understood.

28 Others include “Hidden” hydrothermal resources, supercritical volcanic geothermal, oil and gas co-production and geopressured reservoirs.

29 Massachusetts Institute of Technology. The Future of Geothermal Energy , 2004.Chapter 6: Generating Resources and Ener gy Storage Technologies Sixth Power Plan

6-25 

### Tidal Energy
Tidal energy originates from the loss of the earth ’s rotational momentum due to drag induced by the gravitational attracti on of the moon and other extraterrest rial objects. The conventional approach to capturing tidal energy is through hydroelectric “barrage s” constructed across bays or estuaries. These admit water on the rising tid e and discharge water through hydro turbines on the ebb. The extreme tidal rang e, preferably 20 feet or more, required by this technology precludes their applicati on to very few locations where the landform greatly amplifies the tidal range. Environmental considerations aside, de veloping economical tidal hydroelectric plants in the Northwest using barrage tec hnology is precluded by insuffici ent tidal range. Mean tidal ranges in the Pacific Northwest are between 4.5 an d 10.5 feet with the greatest mean tides found in bays and inlets of southern Puget Sound. A more promising approach to capturing tidal energy in the Northwest is to use kinetic energy of tide-induced currents to generate electricity by water-current turbines. Intermittent tidal current s of three to eight knots occurring locally in Puget Sound and channels within the San Juan Is lands my be sufficient to support tidal current generation. Water current turbin e technology is in the demonstra tion stage of development and several Northwest utilities have secured pre liminary permits to explore this potential.



### Wave Energy

The Northwest coast is one of the better wa ve energy resource areas in the world. The theoretical wave energy potenti al of the Washington, Oregon, a nd Northern California coast is estimated to be about 50,000 average megawatts. The practical potential will be much smaller because of the competing uses of sea space, environmental constraints, and conversion losses. Nonetheless, the developable potential is like ly to be substantial, and could provide the
Northwest with an attractive s ource of low-carbon renewable en ergy. While highly seasonal and subject to storm-driven peaks (winter energy fl ux may exceed summer rates by a factor of 20), wave energy is continuous and is more predic table than wind, characteristics that may reduce integration costs. Though it would be impractic al to capture the full winter energy flux, the seasonal output of a wave energy plant would ge nerally coincide with winter-peaking regional load. A further attribute of wave energy is its location close to we stside load centers.

Numerous and diverse wave energy conversion con cepts have been proposed and are in various stages of development ranging from conceptualiza tion to pre-commercial demonstration. It is too early to say which technologies will eventually prove best for particular conditions. Wave energy conversion devices will need to perform re liably in a high-energy, corrosive environment, and demonstration projects will be needed to pe rfect reliable and economic designs. Successful technology demonstration will be fo llowed by commercial pilot projects that could be expanded to full-scale commercial arrays. Because of pot ential environmental issues and the competition for sea space from commercial and sport fisher ies, wildlife refuges and wilderness areas, shipping, undersea cables, and military exclusion z ones, site suitability should be assessed and siting protocols established in advance of large- scale commercial development. An important role of demonstration projects will be to gain unde rstanding of site suitability, potential conflicts, impacts, and remediation measures. Asse ssments of interconnection and integration requirements are also essential. Northwest util ities are encouraged to support these efforts.

Conversion technology, depth, ambient wave ener gy, ocean floor conditions, and the distance
from shore all affect the cost of this resour ce. A 2004 estimate of the capital and operating costs and electrical productivity of a 90-megawatt comme rcial-scale plant using Pelamis wave energyChapter 6: Generating Resources and Ener gy Storage Technologies Sixth Power Plan

6-26 converters optimized to Northwest conditions yields costs of $140 to $270 per megawatt-hour 30 for the first array. Experience and economie s of production will reduce costs as installed capacity increases. Given the installation of 1,60 0 megawatts of wave en ergy plants globally, an amount appearing feasible by the 2020s, technol ogy learning curves from experience in the wind, solar, and other industries yield expected costs of $80 to $150 per megawatt-hour. Wave energy can compete with other ge nerating resources if costs within the lower portion of this range can be achieved.



## Solar

The amount of solar radiation av ailable for electricity generati on is a function of latitude, atmospheric conditions, and local sh ading. The best solar resource areas in the Northwest are the
inter-mountain basins of south-central and south eastern Oregon and the Snake River plateau of southern Idaho. On an annual average, these ar eas receive about 75 percent of the irradiation received in Barstow, California, one of the best U.S. sites.

Because of its strong summer seasonality, the No rthwest solar resource has potential for serving local summer-peaking load, such as irrigation and air c onditioning, but is less suitable for serving general regional load which is forecast to contin ue to be winter-peaking for many years. There have been no comprehensive studies of site su itability for development, though the potential is large.

Solar energy can be converted to electricity using photovoltaic or solar-thermal technologies.



### Photovoltaics
Photovoltaic plants convert sun light to electricity using soli d-state devices. Because no
combustion or other chemical reactions are i nvolved, power production is emission-free. No water is consumed other than for periodic cleani ng. Power output is variable and battery storage or auxiliary power is required for remote lo ad demanding a constant supply. Grid-connected installations require firm capaci ty and balancing reserves, tho ugh balancing reserve requirements may be mitigated by distributing many small plants over a wide geographic area, thus dampening cloud-driven ramp rates.

Photovoltaic technology is commer cially established and is wi dely employed to serve small remote load too costly for grid service. Str ong public and political s upport has led to attractive financial incentives, so despite the high cost and low productivity, grid-conn ected installations of several hundred kilowatts or more are becoming common in the Northwest. Multi-megawatt, utility-scale insta llations are appearing in the Southwest where economics are improved by high coincidence of plant output and load.

A low-cost photovoltaic plant employs thin film photovoltaic cells mounted on fixed racks. The energy conversion efficiency and ov erall productivity of such a desi gn is low and thin film cells suffer from more rapid degradation than more expensive crystalline si licon cell technology. Crystalline silicon cells operate at higher efficien cy and are more durable, but they are also more costly. Plant productivity can be improved by mounting cell arrays on tracking devices to improve daily and seasonal orientation. Maximum produc tivity is achieved by using

30 Using the reference cost assumptions used elsewhere in this chapter.Chapter 6: Generating Resources and Ener gy Storage Technologies Sixth Power Plan

6-27 concentrating lenses focusing on high-efficien cy multi-junction photovoltaic cells with wide spectral response, mounted on fully automatic dua l-axis trackers. C oncentrating photovoltaic plants operate on direct (focusabl e) solar radiation, so are best suited for clear southwestern
desert conditions.

The reference plant is a 20-megawatt (AC net) , utility-scale station employing flat-plate, nonconcentrating crystalline photovoltaic cells and singl e-axis trackers. The di rect-current output of the modules is converted to alternating current fo r grid interconnection. The relatively small size would permit interconnection at distribution system and sub-transmission voltages, facilitating a high degree of modularity and di stribution across a wide geogra phic area. This would help reduce ramping events driven by cloud movement . The reference plant could yield capacity factors up to 26 percent at the be st Northwest locations. If cons tructed in the near-term, this plant would deliver energy at a bout $280 per megawatt-hour. Costs are expected to continue to decline at the historical average rate of about 8 percent per year.



### Solar Thermal Power Plants
Solar thermal power generation t echnologies (also referred to as concentrating solar power or CSP) use lenses or mirrors to concentrate solar radiation on a heat excha nger to heat a working fluid. The working fluid is used directly or in directly to power a turbine or other mechanical engine to drive an electric generator. CSP t echnologies are broadly cate gorized by the design of the concentrator and the type of thermal engine. The three basic types are parabolic trough, central receiver, and Sterling di sh. Parabolic trough plants, th e most mature, have been in commercial operation in California since the 1980s. Plants have been recently completed in Nevada and Spain. 31 These plants employ arrays of mirrore d parabolic cross-section troughs that focus solar radiation on a linear heat-exchange pipe filled with circulating heat transfer fluid. The hot fluid is circulated through heat exchange rs to generate steam to supply a conventional steam-electric power plant. Para bolic trough plants can be equippe d with auxiliary natural gas boilers to stabilize output during cloudy periods a nd to extend daily operating hours. Plants can also be equipped with thermal storage for the same purpose.

Central-receiver plants employ a fi eld of tracking reflectors (heliostat s) that direct solar radiation
on an elevated central receiver where energy is transferred to a working fluid, usually a molten
salt. The hot molten salt is ci rculated through heat exchangers to generate steam to supply a conventional steam-electric power plant. Molten salt storage tanks are provided to stabilize output during cloudy periods and to extend daily operating hours. Several demonstration plants
have been constructed. The first commercial ce ntral receiver plant, a 17-megawatt unit, is scheduled for 2011 service in Spain.

A Stirling dish consists of a tracking parabolic mirror that concentrates solar radiation on the heat exchanger of a small Stir ling reciprocating engine at th e focal point of the mirror. Individual dishes are small, a nd utility-scale plants would consis t of large arrays of individual
dish units. Because of the small size of the i ndividual units, Stirling dish technology may benefit from economies of standardization and production. However, Stirling dish technology is not suitable for thermal storage. The tec hnology is in the demonstration stage.

31 An in-depth source of information regarding parabolic trough solar-thermal plants is at http://www.nrel.gov/csp/troughnet/.Chapter 6: Generating Resources and Ener gy Storage Technologies Sixth Power Plan

6-28 Concentrating solar plants use direct solar radiati on so are best suited for dry, clear sky locations. Though potentially suitable areas mi ght be found in southern Ida ho and southeastern Oregon, the
most suitable locations are in the Southwest. The reference plant is a 100-megawatt parabolic trough concentrating solar thermal pl ant, with thermal storage, locat ed in east-central Nevada in the vicinity of Ely. Power woul d be delivered to southern Ida ho via the north segment of the proposed Southwest Intertie Proj ect and then to the Boardman area via portions of the proposed Gateway West and the Boardman-to-Hemingway transmission projects. One 500 kilovolt transmission circuit could deliver about 1,500 megawatts of capacity and about 530 average megawatts of energy. Because of the time needed to construct the necessary transmission, it is unlikely that a solar-thermal plant would be avai lable for serving Northwest load prior to 2015. A plant coming into service in 2015 could delive r energy to southern Idaho for about $190 per megawatt-hour. The additional cost of new transmission from Idaho would raise the cost of delivery to Oregon or Wash ington to about $230 per me gawatt-hour. Technological improvements and economies of production are e xpected to result in lower power plant cost.

Solar-thermal technology can provide an abunda nt alternative source of low-carbon energy. Because they can be fitted with thermal stor age and supplementary boilers, parabolic trough and central receiver technologies ha ve the further advantage of pr oviding reliable output through the peak load hours of the day. Th ese technologies are particularly attractive in the Southwest where they can be sited near load at a cost approaching that of co mpeting low-carbon resources. The
added cost and investment risk of long distance transmission needed for these plants make them
less attractive for the Northwest.



## Wind

Northwest wind resource areas include coastal sites with strong but irregular storm-driven winter
winds and summertime north westerly winds. Areas lying east of gaps in the Cascade and Rocky mountain ranges such as the Columbia River Go rge, Snoqualmie Pass, and Marias Pass receive concentrated prevailing westerly winds, occas ional wintertime northerly winds, and winds generated by east-west pressure differentials. Favorable winds are also found on the north-south ridges of southeastern Ore gon and southern Idaho.

Beginning in 1998 with the 25-megawatt Vansycle Ridge project, commer cial wind power has grown to exceed 4,000 megawatts of nameplate capacity, and is now the fourth largest component of the Northwest power system in terms of installed capacity. Though some geographic diversification has occurred, capacity remains concentrated in the area of the Columbia Basin east of the Columbia River Gorge. Nearly 80 percent of the total regional wind capacity is located in a 160 mile corridor fr om The Dalles, Oregon northeast to Pomeroy, Washington.

The rapid rate of development re flects the fundamental attributes of wind power as an abundant, mature, relatively low-cost source of low-car bon energy with local econo mic benefits. These attributes, combined with an ar ray of market and financial ince ntives and strong political support
within the Northwest and elsewhere in the WE CC region are expected to sustain robust development of Northwest wind power.

Wind power in the Northwest has variable output and little firm capacity and therefore requires supplemental firm capacity and balancing reserves. An existing surplus of balancing reservesChapter 6: Generating Resources and Ener gy Storage Technologies Sixth Power Plan

6-29 and firm capacity within the Northwest has enab led the growth of wind power without the need or cost of additional capacity reserves. Howeve r, the concentration of installed wind capacity east of the Columbia River Gorge and within a single balancing area (Bonneville) has led to significant ramping events, putting pressure on Bonneville’s ability to integrate additional wind development.

The least cost and quickest solutions to integr ating additional wind deve lopment appear to be reducing the demand for system flexibility and fu lly accessing the flexibility of the existing system. Measures such as improved load fo recasting, up-ramp curtailment, and sub-hourly scheduling can reduce the amount of flexibility required to in tegrate a given amount of wind capacity. Longer-term, increasing the geographi c diversity of wind development by importing
wind from remote areas could also reduce the dema nd for flexibility. Existing system flexibility,
scattered across numerous Northw est balancing areas, can be mo re fully accessed by developing mechanisms to trade balancing services and by expanding dynamic scheduling capability both within the region and with other lo ad areas. Issues of cost allo cation will need to be resolved, especially now that substantial amounts (close to 50 percent of 2008 deve lopment) of Northwest wind power is marketed to California customers. Following these steps, new balancing reserves and firm capacity from generation, storage or demand-side sources may be required.

The abundance of compatible wh eat and grazing land with good wind resources and available
transmission has minimized environmental conflic ts. As these prime sites are developed and pressure to geographically diversify wind develo pment increases, environmental conflicts may become more common. Identifying sensitiv e areas and establishing transparent and comprehensive permitting criteria and procedures will help avoid potential conflicts.

The Council assessed the cost and potential for co ntinued wind development to meet local needs in the Columbia Basin, Southern Idaho, and Montana. The Counc il also examined the cost of importing wind energy to Northwest load centers from Alberta, Montana, and Wyoming wind resource areas. It is unlikely that wind power from Alberta, Montana, or Wyoming would be available to serve Oregon or Washington load prior to 2015 because of the time needed to construct the necessary transmission. These options are summarized in Table 6-2.Chapter 6: Generating Resources and Ener gy Storage Technologies Sixth Power Plan

6-30 Table 6-2: Cost and Availa bility of New Wind Power (2015) 32

Resource Limiting Factor Capacity (MW) Energy (MWa) Cost ($/MW/hr)
Local Montana 20% peak load penetration 215 80 $89
Columbia Basin > PNW Westside Transmission at embedded cost 4060 1300 $104
Other local OR/WA 20% peak load penetration 340 110 $104
Local Southern Idaho 20% peak load penetration 725 215 $109
Montana > ID New 500kV AC transmission 1500/circuit 570 $116 Wyoming > ID New 500kV AC transmission 1500/circuit 570 $121
Montana > OR/WA via CTS Upgrade Upgrade potential of Colstrip Transmission System 659 244 $128
Alberta > OR/WA New +/-500kV DC transmission 2000/circuit 760 $138

Montana > OR/WA New 500kV AC transmission via S. ID 1500/circuit 570 $147 Wyoming > OR/WA New 500kV AC transmission 1500/circuit 570 $154

To conserve model setup and run time, the four “local” wind resource blocks were consolidated into a single block for the resource portfolio model. For similar reasons, the Montana to Oregon/Washington case was selected as representative of imported wind. 33



## WASTE HEAT ENERGY RECOVERY

Certain industrial processes and engines reject energy at suffici ent temperature and volume to justify capturing the en ergy for electricity production, a pr ocess known as r ecovered energy generation (REG), a form of cogeneration. “Waste heat” is a third priority resource in the Regional Act. 34 Candidate sources of high and medium -temperature waste heat include: cement kilns, glass furnaces, aluminum smelters, metals refining furnaces, open hearth steel furnaces, steel heating furnaces, hydrogen plants, waste inci nerators, steam boiler exhaust, gas turbines and reciprocating engine exhaust, heat treati ng and annealing furnaces, drying and baking ovens, and catalytic crackers. While many of these f acilities are usually equipped with recuperators, regenerators, waste-heat recovery boilers, and other devices to capture a portion of the reject heat, bottoming-cycle cogeneration could also be installed on some of them. Recovered energy generation is attractive because of its effici ency, baseload operation, and little, if any, incremental air emissions or carbon dioxide prod uction. Heat recovery boilers with steamturbine generators are the conve ntional approach to using wa ste heat for electric power generation. However, small-scal e, modular organic Rankine cy cle power plants (Ormat and others) suitable for lower-temperature energy so urces have expanded the potential applications for recovered energy generation.

The reference plant is a 5-megawatt organic Ra nkine-cycle generating unit using exhaust gas from the mechanical drive gas turbines of a natural gas compressor st ation. This unit would operate in baseload mode with some fluctuation du e to seasonal variation in gas flow (coincident

32 Estimates of capacity and energy are of delivered pote ntial, incremental to installed capacity operating or under
construction as of end of 2008.

33 A review of the cost estimates following this initial port folio run suggested that Alberta wind has potential as the least-cost imported wind option for Oregon and Washingt on load. Because of the larger incremental size of imported Alberta wind (2,000 MW vs. 1,500 MW), further an alysis is needed to confirm the least-risk/least cost imported wind option.

34 Northwest Power Act, Section 4(e)(1).Chapter 6: Generating Resources and Ener gy Storage Technologies Sixth Power Plan

6-31 with regional electrical load). At $63 per me gawatt-hour, electricity fr om the reference plant would be among the lowest-cost of the new gene rating resources identified for this plan.

An inventory of potential Nort hwest opportunities for the deve lopment of recovered energy generation was not located; howev er, such opportunities are known to exist. For example, more than 50 natural gas pipeline compressor stations ar e located in the Northwest. Recovered energy cogeneration facilities for trunkline compressor station applications are typically about 5 megawatts in capacity, suggesting significant potential. Cement kilns, steel processing facilities, and glass furnaces offer additional possibilities. Th e potential is sufficiently attractive to warrant an effort on the part of Bonneville and regi onal utilities to identify and develop them.



## FOSSIL FUELS

Coal

Coal resources available to the Northwest incl ude the Powder River ba sin fields of eastern Montana and Wyoming, the East Kootenay fields of southeastern British Columbia, the Green River basin of southwestern Wyoming, the Uint a basin of northeastern Utah and northwestern Colorado, and extensive deposits in Alberta. Coal could also be obt ained by barge from the Quinsam mines of Vancouver Island or the Chu itna mines of Alaska. Mines at Centralia, Washington, have recently closed and the Ce ntralia power plant is now supplied by rail.

Sufficient coal is available to the region to easily support all regiona l electric power needs through the planning period. Improvements in mining and rail haul productiv ity have resulted in generally declining constant dollar production costs. Climat e policy and overseas demand are the important factors affecting fu ture coal prices. Though carbon dioxide penalties would tend to depress future demand and prices, commerciali zation of technologies for separating and sequestering carbon dioxide would rejuvenate dema nd for coal. This plan uses Powder River
Basin coal as the reference coal. The minemout h price of Powder River Basin coal is forecast $0.64/MMBtu in 2010, increasing to $0.71 in 2029 (mediu m case). Transportation adders based on rail costs are used to adjust prices to other locations. Further discus sion of fuel prices is provided in Chapter 2 and Appendix A.

Coal is the major source of electricity in the Un ited States as a whole, but constitutes only 13 percent (7,300 megawatts) of ge nerating capacity and about 25 pe rcent of the electric energy supply in the Northwest. Pu lverized coal-fired steam-el ectric plants, though a mature technology, continue to improve by using higher temperatures and mo re efficient steam cycles. The preferred technology for new North American plants is shifting fr om subcritical steam cycles with thermal efficiency of about 37 percent to supercritical cycles with thermal efficiency of 37 percent to 40 percent. Ultr a-supercritical units with thermal efficiencies of 41 percent to 43 percent are being constructed in Europe a nd Asia and have been proposed in the United
States.

Continuing to use coal for power generation will hinge on efforts to reduce carbon dioxide production. While abundant in th e United States, coal has the hi ghest carbon content of all the major types of fossil fuel. 35 Moreover, conventional coal-fir ed plants operate at a lower

35 The carbon content of petroleum coke is somewhat greater than that of coal.Chapter 6: Generating Resources and Ener gy Storage Technologies Sixth Power Plan

6-32 efficiency than gas-fired plants. Despite the rela tively small penetration of coal capacity in the Northwest, coal combustion is responsible for 85 percent to 90 percen t of the carbon dioxide from the Northwest electricity sector. Re ducing per megawatt-hour carbon dioxide production from coal-fired plants can be achieved by incr eased thermal efficiency, fuel switching, and carbon dioxide capture and sequest ration. For new construction, increasing the efficiency of combustion is the least cost and logical first st ep to reducing carbon di oxide production. Ultrasupercritical plants, for example, produce about 80 percent of the carbon dioxide of conventional coal-fired units. Switching from sub-bitumi nous to certain bituminous coals can reduce carbon dioxide production from existing as well as new plants by several percent, but the economics and net impact on carbon dioxide production are cas e-specific because of coal production and transportation considerations. Co-firing biomass can reduce ca rbon dioxide production, but the biomass quantities and co-firing percentages are limited. Car bon capture and sequestration will be required to control carbon dioxide releases to the levels needed to achieve proposed greenhouse gas reduction targets if continued reliance on coal is de sired. While carbon capture technology for coal gasification plants is commer cially available, captu re technology for steamelectric plants remains under development. Though legal issu es remain, sequestration in depleted oil or gas fields is commercially proven. Suitable oil and gas reservoirs are limited in the Northwest and though other geologic alternat ives are potentially available, including deep saline aquifers and possibly flood basalt seque stration, these remain to be proven and
commercialized.



### Coal-fired Steam-electric Plants
New steam-electric coal-fired power plants increasingly employ supe rcritical or ultrasupercritical technology utilizing increasingly higher steam pressu re and temperature. Fuel prices and variable costs are low, and these plants operate as baseload units. The key challenge
to continued use of coal-fired steam-electric technology is developing an economical technology to separate carbon dioxide from the products of combustion and establishing commercial-scale carbon sequestration facili ties. One approach to carbon diox ide separation for steam-electric plants is oxy-firing, in which the furnace is supplied with pure oxygen, rather than air for combustion. This would produce a flue gas cons isting largely of carbon dioxide and water vapor
from which the carbon dioxide coul d be readily separated. An alte rnative approach is chemical separation of carbon dioxide from the flue gas of a conventional air-fired furnace. The latter appears to be the leading technology, but is unl ikely to be commercially available before 2020.

Because of the lead time required to develop a nd construct a coal-fire d, steam-electric power plant, it is unlikely that a new pl ant could be placed in service unt il the mid-term of the planning period. The reference plant for this period is a 450-megawatt supercritical unit. The plant would be equipped with a full suite of criteria air emission 36 control equipment and activated charcoal injection for reducing mercury emissions. Because the technology is not currently commercial, the reference plant is not provi ded with carbon dioxide separati on equipment. The plant could provide firm capacity and energy services and li mited balancing reserves. This plant would not comply with Washington, Montana or Ore gon carbon dioxide performance standards, and currently could not be constructe d in Idaho because of that st ate’s moratorium on coal-fired power plant development. The estimated levelized lifecycle electricity cost for a this plant at an

36 Emission controlled under the Clean Air act of 1990. These includ e sulfur dioxide, nitrogen oxides, particulates, hydrocarbons, and carbon monoxide.Chapter 6: Generating Resources and Ener gy Storage Technologies Sixth Power Plan

6-33 eastern Oregon or Washington location is $113 pe r megawatt-hour, including forecast levelized carbon dioxide allowance costs of $4 4 per megawatt-hour (2020 service).

By the mid-2020s carbon separation technology for steam-electric plants may be commercially available. Likewise, commercial-scale carbon sequestration facilities may be available, particularly those using depleted oil and gas fields. Also by this time, new steam-electric plants are likely to employ higher-effici ency ultra-supercriti cal steam conditions. The reference plant for this period is a 450-megawatt ultra-supercritical unit, equipped for rem oval of 90 percent of flue gas carbon dioxide. This plant could co mply with Washington, Montana or Oregon carbon dioxide performance standards and supplement or replace existing coal-fired units. The example is assumed to be a repower of the existing Colstrip transmission system. The estimated levelized lifecycle electricity cost is $143 per megawatt-hour, including transmission costs of $16 per megawatt-hour and carbon dioxide sequestration and residual allowance costs of $31 per megawatt-hour (2025 service). Electricity from this plant would be much more expensive than the forecast cost of power from a gas combined -cycle plant without carbon separation; however, the coal plant would not bear fuel price vola tility risk associated with natural gas-fired generation.



### Coal-fired Gasification Combined-cycle Plants

Pressurized fluidized-bed combus tion and coal gasification technol ogies allow the application of efficient gas turbine combined-c ycle technology to coal-fired ge neration. This reduces fuel consumption, improves operating flexibility, and lowers carbon dioxide production. Of the two technologies, coal gasification is further along in commercial development and offers the benefits of low-cost mercury removal, superi or control of criteria air emissions, optional separation of carbon for sequestra tion, and optional co-producti on of hydrogen, liquid fuel, or other petrochemicals. Several coal gasifica tion project proposals we re announced in North America during the early 2000s. However, escala ting costs and refined engineering indicating that non-carbon emissions and plant efficien cy would not be signi ficantly better than supercritical steam electric plants has dampened enthusiasm. Uncertainties regarding the timing and magnitude of greenhouse gas regulation and th e availability of carbon sequestration facilities
have further clouded the future of these plants and only a hand ful of proposals remain active.

Because of the lead time required to develop a nd construct a coal gasification combined-cycle power plant, it is unlikely that a new plant could be placed in service until the mid-term of the planning period. The reference plant is a 623 megawatt integrated co al-fired gasification combined-cycle plant using an oxygen-blown Conoco-Philips gasifier , sulfur recovery, particulate filters, and carbon bed mercury contro l. The Conoco-Philips technology is thought to
be suitable for sub-bituminous Powder River Basi n coal, and could also be fired with bituminous coal or petroleum coke. The clean synthesis gas supplies a gas turbin e combined-cycle power generation plant that would provi de firm capacity, energy, and ba lancing reserves . This plant would not comply with Washington, Montana or Oregon carbon dioxide performance standards, and currently could not be constructed in Idaho b ecause of that state’s moratorium on coal-fired power plant development. The estimated leveli zed lifecycle electricity cost for an eastern Oregon or Washington location is $118 per mega watt-hour, including forecast levelized carbon dioxide allowance costs of $41 pe r megawatt-hour (2020 service).

The reference IGCC plant for the long-tem is e quipped to remove 88 percent of flue gas carbon dioxide. This plant could comply with Washington, Montana or Oregon carbon dioxideChapter 6: Generating Resources and Ener gy Storage Technologies Sixth Power Plan

6-34 performance standards and supplement or replace existing coal-fired units. The representative plant is a repower of the existing Colstrip transm ission system. The estimated levelized lifecycle electricity cost is $121 per megawatt-hour, incl uding transmission costs of $17 per megawatthour and carbon dioxide sequestration and resi dual allowance costs of $31 per megawatt-hour (2025 service).



## Natural Gas

Natural gas is a mixture of naturally occurri ng combustible gases, in cluding methane, ethane, propane, butane, isobutene, and pentanes f ound in porous geologic structures, often in association with petroleum or coal deposits. Raw natural gas is recovered by means of wells, and is processed to remove the condensable frac tions (propane, butane, isobutene and pentanes), carbon dioxide, water, and impurities. The resulting product, consisting of methane (~90 percent) and ethane is odori zed and compressed for transport by pipeline to markets. The “natural” natural gas supply can be slightly augmented with methane recovered from landfills and from anaerobic digestion of organic wastes. Methane can also be synthesized from coal.

Natural gas is a valuable energy resource beca use of its clean-burning properties, ease of transportation, low carbon dioxide pr oduction and diversity of applicat ions. Gas is used directly for numerous residential, commercial, and indus trial end uses and to produce electricity using steam, gas turbine, and reciprocating engine t echnologies. Natural gas is also the principal
feedstock in the manufacture of amm onia and ammonia-based fertilizers.

Low natural gas prices and the development of efficient, low-cost, environmentally attractive gas-fired combined-cycle power pl ants led to a surge of construc tion early in the 1990s and again following the 2000/2001 energy crisis. Natural ga s power plants represent about 16 percent (9,100 megawatts) of Northwest generating capac ity. Of this, 6,960 megawatts are combinedcycle units, 1,830 megawatts are peaking units, and 350 megawatts are industrial cogeneration
units.



### Natural Gas Supply and Price
Though natural gas has been produced in Montana, a nd to a limited extent in local areas west of the Cascades, the Pacific Northwest does not have significant indigenous ga s resources. Rather, gas is imported by pipeline from the Western Canada Sedimentary Basin of Alberta and British Columbia, the Rocky Mountain Basin of Wyomi ng and Colorado, and the San Juan Basin of New Mexico. Rising natural gas prices following the energy crisis of 2000-01 prompted interest in constructing liquefied natural gas (LNG) term inals to secure access to lower-cost overseas supplies. Interest in LNG facilities has waned because of declining gas prices due to falling demand, expansion of unconventional sources such as coal-bed methane and tight formations,
and new conventional discoveries in British Columbia.

Worldwide, the proven reserves-to-production ratio of natural gas has declined in recent years, from a recent high of about 68 years in 2001 to 60 years in 2008. 37 With limited LNG-transfer capacity, North America is largely a self-contai ned market with a much lower reserves-toproduction ratio, about 10 years. However, a significant amount of natural gas remains undiscovered and reserves have trended upward fo r many years, more than offsetting increasing

37 BP Statistical Review of World Energy , June 2009.Chapter 6: Generating Resources and Ener gy Storage Technologies Sixth Power Plan

6-35 consumption. 38 New sources of supply, including “Front ier Gas” from the Alaskan North Slope and the McKenzie Delta, unconventional sources su ch as coal bed methane and tight sands, U.S. and Canadian offshore fields, and LNG are exp ected to make up shortfalls and set North American marginal prices in the long-term. Natural gas delivered on a firm basis to a power plant east of the Cascades is forecast to increase from $4.48/MMBtu in 2010 to $7.72/MMBtu in 2029 in the medium case (about 2.2 percent/year in constant 2006 dollars). Westside prices are expected to run about 50 to 60 cents per MMB tu higher. Unpredictable periods of price volatility are likely to occur during this peri od. The natural gas pric e forecast is further discussed in Chapter 2 and Appendix A.



### Natural Gas Generating Technologies
Natural gas and liquid petroleum products are the mo st flexible of energy resources in terms of technologies and applications. Ge nerating technologies that can be fueled by natural gas include steam-electric plants, gas turbin e generators, gas turbine combin ed-cycle plants, reciprocating engine generators, and fuel cells. Applicati ons run the gamut: base-load energy production, regulation and load-following, peaking, cogenera tion, and distributed generation. Gas turbine generators, combined-cycle plants, and reciprocati ng engines are expected to continue to play a major role in electricity produc tion. Fuel cells and microturbines may see some specialized applications, but appear unlikely to be major player s in the near- to mid-te rm because of cost and reliability issues.



### Simple-cycle Gas Turbine Power Plants
Simple-cycle gas turbine power plants (also called gas turbine gene rators or combustion turbines) consist of one or two combustion gas turb ines driving an electric generator. These are compact, modular generating plants with rapid-response startup and load-following capability, and are extensively used for mee ting short-duration peak load. A wide range of unit sizes is available, from sub-megawatt to 270 megawatts. Low to moderate capital costs and superb operating flexibility make simple-cycle gas turb ines attractive for peak ing and grid support applications. Though the inherent operating flexibility of these un its is suitable for providing regulation and load following, conve ntional frame or aeroderivativ e simple-cycle units are not often used for this purpose because of their relative ly low efficiency and the cost of natural gas. Likewise, simple-cycle gas turb ines are rarely been used fo r baseload energy production unless equipped with exhaust heat rec overy cogeneration. Higher-efficien cy intercooled gas turbines have recently been introduced with the objec tive of providing regula tion and load-following services. All gas turbine genera tors feature highly modular cons truction, short construction time, compact size, and low water consumption. 39 Equipment is available to control air emissions to
low levels.

Because of the ability of the hydr opower system to supply peaking and flexible capacity, simplecycle gas turbines have historically been a minor element of the Northwest power system. However, simple-cycle gas turbines have been a dded to the Northwest system in recent years to provide energy during poor water conditions, to support cogeneration loads, to support increasing summer peak loads and to provi de regulation and load-following services.

38 Energy Information Administration. International Energy Outlook 2008 (DOE/EIA-0484(2008)). June 2008. Fig.
43.

39 Larger amounts of water are required for intercooled or cogeneration units and units using air inlet evaporative cooling or water injection for power augmentation or nitrogen oxide control.Chapter 6: Generating Resources and Ener gy Storage Technologies Sixth Power Plan

6-36 Gas turbine generators are generally divided into three classes: heavy-du ty industrial machines specifically designed for stationary applications (so-called “fram e” machines), “aeroderivative” machines using aircraft gas-turbine engines ad apted to stationary applications, and “hybrid” intercooled machines with high part-load efficien cy (the GE LMS100) intended for intermediate and load-following applications. Gas turbines fo r power generation benefit from research driven by military and commercial aircra ft applications, and though a mature technology, improvement in gas turbine performance is expected to continue in the coming decades.

The reference frame plant consists of a single 85-megawatt (nominal) capacity unit located at an existing gas-fired power plant site . Natural gas is supplied on a fi rm gas transportation contract with capacity-releas e capability. No backup fuel is provi ded. Air emission controls include water injection and selective catalytic reducti on for nitrogen oxide control and an oxidation catalyst for carbon and volatile or ganic compound reduction. This type of plant would normally serve peak load and provide replacement reserv es. The levelized total fixed capacity cost (capital, fuel, O&M, and transmission) fo r 2015 service is $134 pe r kilowatt-year.

The reference aeroderivative plant consists of two 45-megawatt (nominal) aeroderivative gas turbine generators located at an existing gas-fired power plant s ite. Natural gas is supplied on a firm gas transportation contract with capacity-r elease capability. No backup fuel is provided.
Air emission controls include wate r injection and selective cataly tic reduction for nitrogen oxide control and an oxidation catalys t for carbon and volatile organic compound reduction. This type of plant would normally serve peak load. Its ra pid startup (less than 10 minute) capability would also allow it to provide rapid-response reserv es while shutdown. The levelized total fixed capacity cost (capital, fuel, O&M, and transmi ssion) for 2015 service is $164 per kilowatt-year. Levelized energy cost is estimated to be $130 per megawatt-hour if the pl ant were operated as a 4000 equivalent full power hour per year intermediate load facil ity, as might be the case if providing balancing capacity.

The reference intercooled plant consists of a 100-megawatt (nominal) hybrid intercooled gas turbine generator located at an existing gas-fire d power plant site. Natu ral gas is supplied on a firm gas transportation contract with capacity-r elease capability. No backup fuel is provided.
Air emission controls include wate r injection and selective cataly tic reduction for nitrogen oxide
control and an oxidation catal yst for carbon and volatile organi c compound reduction. The higher efficiency and flatter heat rate cu rve of this type of plant would allow it to serve intermediate as well as peak load, and economica lly provide balancing reserves as well as rapid-response and replacement reserves. The levelized total fi xed capacity cost (capital, fuel, O&M and transmission) for 2015 service is $16 4 per kilowatt-year. Levelized energy cost is estimated to be $126 per megawatt-hour if the plant were ope rated as a 4000 equivalent full power hour per year intermediate load facility, as might be the case if providi ng balancing capacity.



### Reciprocating Engine-generators
Reciprocating-engine ge nerators (also known as internal co mbustion engines, ICs or gen-sets) consist of a compression or spark-ignition recipr ocating engine driving a generator, typically mounted on a frame and supplied as a modular unit. Unit sizes for power system applications range from about 1 to 15 megawatts. Conventi onally, reciprocating generators are used for small, isolated power systems, emergency capacity at sites susceptible to transmission outages, and to provide emergency power and black start ca pacity at larger power plants. Other power system applications include units modified to operate on biogas from landfills or anaerobicChapter 6: Generating Resources and Ener gy Storage Technologies Sixth Power Plan

6-37 digestion of waste biomass, mobile units for emer gency service, and “recip farms” installed as a hedge to high power prices dur ing the 2000-2001 energy crisis. On the load side, reciprocating units are permanently installed to provide backup power for hospitals, elevators, and emergency lighting in high-occupancy buildings and other critical load. Except for biogas units, these applications typically use li ght fuel oil stored on site.

The introduction of more efficient and cleaner r eciprocating generators in recent years, coupled with the increasing need for lo ad-following services for wind ge neration, has increased interest in the use of arrays of gas-fi red reciprocating generators to provide peaking and load-following services. A typical installation c onsists of five to 20 units of 3 to 16 megawatts capacity each. The resulting plant is highly re liable with high efficiency across a wide load range; ideal for load-following. Because the output of reciprocati ng engines is less sensitive to elevation than gas turbine output, reciprocating units may be ad vantageous for higher-elevation locations for peaking and load-following applications. Recipro cating units can also be fitted with exhaust, turbocharger, and lube oil heat recovery for low-temperature cogeneration load.

The reference plant consists of 12 8-megawatt un its operating on natural gas supplied on a firm gas transportation contract with capacity release capability. Air emission controls include selective catalytic redu ction for nitrogen oxide control a nd an oxidation catalyst for carbon and volatile organic compound reduction. This pl ant can provide regula tion and load-following, contingency reserves, and other an cillary services. The relatively high efficiency (41 percent) allows the plant to economically serve peak and ev en intermediate loads. The capacity cost of this plant is estimated to be $172/kW-year. Leve lized energy cost is es timated to be $135 per megawatt-hour if the plant we re operated as a 4,000 equiva lent full power hour-per-year intermediate load facility, as might be the case if providing balancing capacity.



### Combined-cycle Gas Turb ine Power Plants
Gas turbine combined-cycle power plants consist of one or more gas turbine generators provided with exhaust heat recovery steam generators. St eam raised in the heat recovery units powers a steam-turbine generator, increasing the overall th ermal efficiency of the plant compared to simple-cycle gas turbines. Th e reference combined-cycle unit, for example, has a baseload efficiency of 49 percent compared to a full-load efficiency of 36 percent for the reference hybrid intercooled gas turbine. Combined-cycle plants can serve cogeneration steam load (at some loss of electricity production) by extracting steam at the needed pressure fr om the heat-recovery steam generator or steam turbine. Additional ge nerating capacity (power augmentation) can be obtained at low cost by oversizing the steam turb ine generator and providi ng the heat recovery steam generator with natural gas burners (duct fi ring). Because the resulting capacity increment operates at somewhat lower electrical efficiency than the base plant, it is usually reserved for peaking operation. Because of thei r reliability and efficiency, low capital costs, short lead-time, operating flexibility, and low air emissions, gas-fired combined-cycle plants have been the bulk power generation resource of choice since the early 1990s.

The reference plant is a single advanced “H-cla ss” gas turbine generato r and one steam turbine generator. The base-load capacity is 390 mega watts with an additional 25 megawatts of ductfiring power augmentation. Fuel is natural gas supplied on a firm transportation contract with capacity-release capability. No backup fuel is pr ovided. Air emission controls include dry lownitrogen oxide combustors and selective catalytic reduction for nitrogen oxide control and an oxidation catalyst for carbon and volatile organi c compound control. Condenser cooling is wetChapter 6: Generating Resources and Ener gy Storage Technologies Sixth Power Plan

6-38 mechanical draft. In the Northwest, this pl ant would operate in baseload mode during the summer and winter seasons and as a marginal plant during high hydro runoff and low load seasons. The plant could also operate at partial (80 – 90 percent) load to provide regulation and load-following, though at some sacrifice in e fficiency. Year-round baseload operation (80 percent of full load capacity) would yield reference ener gy costs of $92 per megawatt-hour including forecast carbon dioxide allowance co sts of $18 per megawatt-hour. More typical operation in the Northwest at capac ity factors ranging from 65 pe rcent to 35 percent would result in reference electricity produc tion costs from $97 to $122 per megawatt-hour. Cogeneration revenues could slightly redu ce electricity production costs. 40



## Petroleum

Petroleum fuel, including propane, distillate, and residual fuel oils are universally available at prices largely determined by the global market. In general, other than for special uses such as for backup fuel, peaking or emergency service power plants, and power generation in remote areas where its transportability and storability are es sential, petroleum-derived fuel cannot compete with natural gas for electric power generation. Forecast prices for petroleum fuel are discussed in Chapter 2 and Appendix A.



## Petroleum Coke

Petroleum coke is a carbonaceous solid byproduct of cracking residual fuel oil in a delayed coker to extract higher value products. The supply of petroleum coke is increasing as refineries increasingly crack residual fu el oil to yield higher value pr oducts and draw upon lower quality crudes. The Energy Information Administration repor ts that the refinery yield of petroleum coke has increased from 4.3 percent in 1995 to 5.3 percen t in 2008 (as percent of total refinery product slate). Higher purity petroleum coke is used for aluminum smelting anodes, whereas fuel-grade petroleum coke is primarily used for firing cemen t kilns and power plants. About two-thirds of the merchantable petroleum coke originating in U.S. refineries is exported, primarily to Latin America, Japan, Europe, and Canada. The remainder is gasified in refinery trigeneration plants or marketed to electric power generators, calcin ers, cement kilns, and other industries. Because
of its low ash content and very high heating value (14,000 Btu/lb compared to 8,000 - 8,800 Btu/lb for Power River Basin coal), petroleum c oke transportation costs are lower than for coal on a Btu basis. However, petroleum coke is usua lly priced at a discount to coal because of its typically higher sulfur and metals content. Because refineries can economically dispose of petroleum coke at a loss because of the adde d value of the lighter products obtained from cracking residual, there is a great deal of pricing flexibility and the discount to coal is highly variable. Further discounting ma y occur in the future because of the higher carbon content of petroleum coke compared to coal (225 vs. 212 pounds per million Btu). Based on limited available pricing information, the discount to subbituminous coal is about 80 percent.

Gasification combined-cycle plants would be the preferred technology for power generation using petroleum coke because of the superior abil ity to control sulfur and heavy metals, and in the longer term, to capture and sequester carbon dioxide. Because of possible supply limitations and fluctuating prices relative to coal, it is likel y that a plant would be fueled using a blend of

40 Combined-cycle cogeneration plants normally support a relatively small steam load.Chapter 6: Generating Resources and Ener gy Storage Technologies Sixth Power Plan

6-39 petroleum coke and coal. This plant, however, would not comply with Washington, Montana or Oregon carbon dioxide perf ormance standards.



## NUCLEAR

Nuclear power plants produce electricity from ener gy released by the controll ed fission of certain isotopes of heavy elements such as uranium, thorium, and plutonium. Commercial light water reactors used in the United States are normally fu eled with a mixture of two isotopes of natural uranium, about 3 percent fissionable U-235 and 97 percent non-fissionabl e, but fertile U-238.
The U-238 is transmuted to fissionable Pu-239 wi thin the reactor by absorption of a neutron. Though reactors using thorium and “bred” pluton ium have been developed in anticipation of eventual shortages of natural uranium, it appear s that the industry can re ly on abundant supplies
of natural uranium for the foreseeable future. The price of fabricated nuclear fuel is forecast to be relatively stable, averaging $0.73/ MMBtu through the planning period.

Commercial nuclear plants in the United Stat es are based on light water reactor (LWR) technology developed in the 1950s. One unit, the 1,200-megawatt Columbia Generating Station operates in the Northwest. Motivated by impr oved plant designs, the need for new low-carbon
baseload resources and financial incentives of the Energy Policy Act of 2005, nuclear development activity has resumed in the United St ates following a three-decade hiatus. As of late 2009, developers have submitted applications to the Nuclear Regulatory Commission for combined construction and opera ting licenses for 27 new units at 17 sites, largely in the southeast. Most proposals are plan ned for service in the late teens, and construction of the initial units is expected to be contingent on fe deral incentives. The proposed plants employ evolutionary LWR designs with increased use of passively operated safety systems and factoryassembled standardized modular components. These features should improve safety, reduce cost, and increase reliability.

Work is also underway on developing small modu lar reactors (SMRs). SMRs are conceived as modular, scalable, largely factor y-assembled plants of 25 to 350 megawatts generating capacity. Compared to 1,100 to 1,800 megawatt conventional reactors, the smaller size and modular
construction of SMRs are intended to reduce ca pital cost and investme nt risk by employing a greater degree of factory assemb ly, shortening construction lead time and better matching plant size to customer needs through scaling of multiple units. Smaller plant size may also permit greater siting flexibility and cogeneration poten tial and can benefit system reliability through reduction in “single-shaft” out age risk. Proposed SMR designs offer improved safety through features such as integral cons truction (all reactor coolant sy stems contained within a single pressure vessel), below-ground emplacement, and lif etime, factory-installed fuel supplies. The SMR concept is not new or unique - over 50 SMR designs have been proposed - however, the enormous investment and long lead time needed to construct conventiona l reactor plants plus increasing interest in deployi ng carbon-free nuclear technology in developing countries has resulted in unprecedented interest in SMR t echnology. Completion of the first demonstration SMRs is at least a decade away. Designs must be completed, NRC design certification secured, and demonstration projects permitted, financed, constructed and tested.

Nuclear plants could be an at tractive source of dependable ca pacity and baseload low-carbon energy that is largely immune to high natural gas prices and climate policy. However, a new
nuclear unit would entail the risks of constructio n delay, regulatory uncertainty, escalating costs,Chapter 6: Generating Resources and Ener gy Storage Technologies Sixth Power Plan

6-40 and the reliability risk associated with a large single-shaft machine. The reference plant is a single 1,100 megawatt advanced -light water reactor un it. The reference cost of power from this unit is estimated to be $108 per megawatt-hour ( 2025 service). Construction of a new unit in the Northwest would likely require th e successful completion and operati on of at least one of the proposed new units elsewhere in the United Stat es, established spent-nu clear fuel disposal policy, and aggressive development of equally cost-effective conservation and renewable resources. These conditions would likely preclu de operation of a new conventional nuclear plant in the Northwest prior to the early to mid-2020s.



## ENERGY STORAGE TECHNOLOGIES

A challenge to increasing the pene tration of variable-output rene wable resources like wind, solar, wave, and tidal current generation is shaping the variable and not fully predictable output of these resources to meet the power quality standard s and load of the power system. One approach is to use dispatchable firm generation like hydro power, which is currently used to integrate wind power in the Northwest. An alternative is energy storage technol ogies. Energy storage technologies decouple the production and consumption of electric ity, and can provide regulation, sub-hourly load-following, hour-to-hour storage and shaping, firm capacity, and other ancillary services. Storage projects locate d within a renewable resource z one could flatten the output of variable-output generation, thereby increasing transmission load factors and improving the economics of long-distance transmission.

A variety of storage technologi es are commercially available or under development, including pumped storage hydropower, compressed air ener gy storage, numerous types of electrically rechargeable batteries, metal-air batteries, several types of flow batteries, flywheels, electromagnets, and capacitors. Fo r the foreseeable future, only a s ubset of these have the “bulk” or “massive” energy storage potential needed to integrate utility-scale renewable energy

resources. 41 This requires megawatt-scale power ratings, run times of hours and extended charge/discharge capability. The most prom ising systems include compressed air energy storage, flow batteries, pumped-storage hydropower, and sodium-sulfur batteries.

A common constraint to deploying energy storage systems is th at the project developer is unable to capture the full value of the system’s services. The ge neration, transmissi on and distribution sectors may each realize benefits, but it is often difficult for the de veloper of a storage project to fully capture the benefits of his project. No formal market exists in the Northwest for the services provided by energy storage systems, and with one exception, 42 no successful example of non-utility development of a utility-scale storage project is found in the West.

A second constraint is the need for frequent cycling. Amortizati on of the capital cost of these technologies, which tends to be relatively high, requires that they be employed frequently and for as many services as they are capable of deliv ering. One reason little pumped storage capacity has been developed in the Northwest, despite favorab le sites, is that most of the region does not experience strong daily summer-afternoon peaks in energy use, which would create a daily offpeak/on-peak arbitrage opportunity co mmon to other areas of the country.

41 Individual units need not be at a megawatt/hour scale. Megawatt/hour scale could be achieved by deploying a large number of responsive grid-conn ected small-scale units, as for exampl e provided by the aggregate storage capability of a fleet of plug-in hybrid vehicles.

42 The 40-megawatt Olevenhain - Ho dges project near San Diego.Chapter 6: Generating Resources and Ener gy Storage Technologies Sixth Power Plan

6-41 

## Compressed Air Energy Storage

A compressed-air energy storag e (CAES) plant is an early commercial technology that can provide load-following and ener gy shaping over periods up to se veral days. “Conventional” compressed air energy storage plants consist of motor-driven air compressors that use low-cost, off-peak electricity to compress air into an underground cavern. During high-demand periods, the stored energy is recovered by releasing the compressed air through a natural gas-fired combustion turbine to generate electricity. The compressed air reduces or eliminates the normal gas turbine compression load, greatly reducing its fuel consumption. A CAES combustion turbine might have a heat rate of 4,000 Btu/ kWh compared to the 9,300 - 12,000 Btu/kWh heat rate of a stand-alone simple-cycle gas turbine. The efficiency of the process is further improved by heating the compressed air with the combustion turbine exhaust prior to introducing it to the
turbine combustors. The economics of a conven tional CAES plant requires sufficient spread between on- and off-peak prices to cover compre ssion and storage losses (about 25 percent) plus the cost of the natural gas used to fire the gas turbine. Economic amortization of the capital cost requires frequent cycling such as that needed to serve a daily summer peak load in a warm
climate.

Two compressed-air energy storag e plants are currently in ope ration. The first 290-megawatt plant was placed into operation in Germany in 1978. A 110-megawatt plant using an improved design, including turbine exhaus t recuperators, was constructe d in 1991 in Alabama. These plants were intended to shift energy from off-p eak hours to on-peak hours in power systems with low-cost, coal-fired baseload en ergy. However, the inherently high degree of flexibility of CAES plants would make them capable of lo ad-following and for shap ing the output of wind generation. The Arkansas project has storage ca pacity for 26 hours of full-load operation, and can ramp from standby to full load in about five minutes. CAES plants located at remote wind resource areas could shape wind project output to im prove the transmission load factor. The fast start and rapid ramp rate capability could provi de decremental load following capability. High part-load efficiency could provi de economic load-following capabi lity compared to conventional simple-cycle gas turbines.

A variety of second generation CAES concepts have been advanced to integrate variable-output renewable resources. Unlike earlier designs, these plants would us e standard industrial components, multiple motor-driven compressors, and separate multiple air expansion turbinegenerators to improve efficiency, provide a dditional operating flexibil ity, and reduce cost. Concepts include a no-fuel adiabatic CAES in which the thermal energy of compression would
be stored as a substitute for fuel in the expansion-generation process.

Potential locations are available in the Northwest. Solution-mined salt caverns, excavated hard rock chambers, depleted oil or natural gas fields , or other porous geologi c media could be used for the compressed air storage reservoir. R ecent proposals for small-scale (~ 15 megawatts) CAES would employ above-ground pressure vessel s or buried high-pressure piping, further increasing siting flexibilit y, though at greater cost.

CAES technology has potential in the Northwest to improve the load factor of transmission used to deliver power from remotely located wind a nd solar generation, and for within-hour and hourto-hour load-following and shap ing services. An advantage compared to pumped storage hydropower is greater siting flexib ility. A disadvantage (except fo r adiabatic concepts) is theChapter 6: Generating Resources and Ener gy Storage Technologies Sixth Power Plan

6-42 need for natural gas to fire th e output generator and the resulting air emissions. The available cost information is not adequate to support a mean ingful comparison of CAES with alternatives. Though cost estimates have been published for the various second generation CAES concepts, these are preliminary and suitable only for co mparison among CAES alternatives. Moreover, CAES costs are sensitive to geology and stor age volume. Second generation demonstration project results and a Northwest f easibility study would be required to accurately fix the relative
cost of CAES and other sour ces of system flexibility.



## Flow Batteries

First used in 1884 to power the airship La France , flow batteries are a re chargeable battery with external electrolyte storage. The electrolyte is pumped through a stack of electrolytic cells to charge or discharge the battery. External electrolyte storage permits independent scale-up of energy storage capability (governed by storag e tank capacity) and power output (governed by cell area and electrolyte transfer ra te). Flow batteries are charac terized by rapid response, ability to hold charge, and longevity in terms of charge/discharge cycl es. Three technologies are under development: vanadium redox, zinc bromine, and polysulfide bromine. Flow batteries offer modularity, sizing flexibility, siting flexibility, and zero em ission operation. A potential disadvantage is their relatively lo w energy density, requiring large el ectrolyte storage facilities to achieve needed energy storage capability.

Flow battery technology is in the demonstration st age. Several installations up to 500 kilowatt capacity and five megawatt-hour storage capac ity are reported in Japan and a 2-megawatt capacity demonstration pr oject is under construc tion in Ireland. Cycle efficiency is 70 to 75 percent with the potential for improvement. Capital costs are relatively high--one U.S. demonstration plant of 250 kilowatts capacity an d 2 megawatt-hours of storage is reported to have cost $4,000 per kilowatt. However, cu rrent cost and performance is likely not representative of production units.



## Pumped-storage Hydropower

Pumped-storage hydropower is an establishe d commercially mature technology. A typical project consists of an upper reservoir and a lowe r reservoir connected by a water transfer system with reversible pump-generators. Energy is stor ed by pumping water from the lower to the upper reservoir using the pump-generators in mo tor-pumping mode. Energy is recovered by discharging the stored water through the pump-gene rators operating as turbine-generator mode. Cycle efficiency ranges from 75 percent to 82 percent. Seventeen pum ped-storage projects constituting more than 4,700 megawatts of capac ity are installed in WECC. One project is
located in the Northwest--the 6-unit, 314 megawatt Grand Coul ee pumped-generator at Banks Lake. This plant is primarily used for pumpi ng water up to Banks Lake, the headworks of the Columbia Basin Irrigation System.

Most existing pumped-storage projects were designed to shift energy from nighttime low variable-cost thermal units to afternoon peak-loa d periods on a daily cycle. However, pumped storage can also provide capacity, frequency re gulation, voltage and reactive support, loadfollowing, and longer-term shaping of energy from variable-output resources without the fuel consumption, carbon dioxide production, and othe r environmental impacts associated withChapter 6: Generating Resources and Ener gy Storage Technologies Sixth Power Plan

6-43 thermal generation. Importantly for the Northw est, pumped storage could provide within-hour incremental and decremental respons e to wind ramping events.

Pumped-storage projects require suitable topography and geol ogic conditions for constructing upper and lower reservoirs at significantly di fferent elevations within close proximity. Subsurface lower reservoirs are technically f easible, though much more expensive. A water supply is required for initial re servoir charge and makeup. Current ly, 13 pumped storage projects ranging in size from 180 to 2,000 megawatts and totaling nearly 14,000 megawatts have been proposed in Idaho, Oregon, and Washington, sugg esting no shortage of suitable sites. Construction costs are project-specific. Factors influencing cost include the availability of an existing water body that can be used for one of the reservoirs (usually the lower), storage capacity, and transmission inte rconnection distance. Though $1,000 per kilowatt of installed capacity is often quoted as a representative cost of pumped storage hydro, a review of available cost estimates suggests that $1,750 to $2,500 per kilowatt 43 is more representative of current construction cost. The principal constraints to pumped storage development are the complexity and lead time of the development process, capita l cost, and the recovery of revenues for the services provided.



## Sodium-sulfur Batteries

A sodium sulfur battery is a high energy-de nsity high-temperature rechargeable battery consisting of molten sodium and molten sulfur electrodes separated by a ceramic electrolyte. The technology is in the early comm ercial stage with about 190 in stallations in Japan, totaling about 270 megawatts capacity. About 9 megawatts of sodium-sulfur battery capacity is installed in the United States. The largest unit in opera tion is Rokkasho in Northern Japan, a 34-megawatt unit with a 245 megawatt-hours storage capability us ed to integrate wind pow er. Advantages of sodium-sulfur batteries include high energy de nsity, high cycle effici ency (89 percent), modularity, siting flexibility in ei ther centralized or distributed configurations. Sodium-sulfur batteries are currently modera tely expensive with capital costs in the $2,500 - 3,000 per megawatt range but increasing pr oduction rates are e xpected to lead to cost reductions.



## SUMMARY OF REFERENCE PLANT CHARACTERISTICS

Key planning characteristics of the reference power plants are co mpiled in Table 6-3. Derivation of these values is described in Appendix I. The definitions of the values appearing in the table
are as follows:

Plant size: The unit size (installed capacity) us ed in the Council’s planning models.
Heat rate: The fuel conversion efficiency of fuel -burning technologies in Btu/kWh. Degraded lifecycle average. Higher heating value ( HHV) for consistency with fuel pricing. Availability/Capacity factor: Availability ((1 - forced outage rate)*(1 - scheduled outage rate)) for firm capacity technologies. Expected capacity factor (adjusted for availability) for energylimited technologies. Total plant cost: The overnight (instantaneous) projec t development and construction cost in constant 2006 year dollar values as of mid-2008. Includes direct and indir ect construction costs, engineering, owner’s development and admini stration costs and contingencies. Excludes

43 Overnight costs.Chapter 6: Generating Resources and Ener gy Storage Technologies Sixth Power Plan

6-44 financing fees and allowance for funds used during construction. Constr uction costs must be adjusted as described in Appendix I to arrive at the expected cost for a given service year. Capital and fixed operating costs are assumed to be fixed at start of construction. Fixed O&M: Fixed operating and maintenance cost in constant 2006 year dollars as of mid2008. Includes operating labor, maintenance co sts and overhead. Interim capital replacement costs included if significant. Excludes propert y tax and insurance. Fixed O&M costs must be adjusted as described in Appendix I to arrive at the expected cost for a given service year. Variable O&M: Variable operating and maintenance cost s in constant 2006 year dollars as of mid-2008. Includes consumables such as water, ch emicals and lubricants. Excludes the cost of
CO 2 sequestration for examples with CO 2 separation and sequestration. Integration cost: The cost of providing regulation and sub-hourly load-following services for system integration. These increase over the pl anning period. Forecast values are provided in Appendix I. Excludes the cost of storage for shaping to load.
Transmission cost: The cost of dedicated long-distan ce transmission, if any, plus within-region wheeling cost. Transmission losses: Total transmission losses (Long-distance transmission plus point-to-point within-region delivery). Plant development and construction: The first value is the time in months to develop a project from conception to first major expenditure (gen erally major equipment order); The second value is the time in months to complete construction of one unit from the first major expenditure. Excludes time required for developing and constr ucting long-distance transmission for remote resource examples. Earliest service year: Assumed earliest service for new plants.. Developable potential: The estimated total developable potential of ener gy-limited resources over the 2010 - 2029 period.Chapter 6: Generating Resources and Energy Storage Technologies Sixth Power Plan6-45Table 6-3: Key Planning Assumptions for Reference Power PlantsReference PlantPlant Size (MW)Heat Rate(HHVBtu/kWh)CapacityFactor/AvailabilityTotalPlantCost($/kW)FixedO&M($/kW/yr)VariableO&M($/MWh)IntegrationCostTransCost44($/kW/yr)TransLosses45Plant Dev /Construction(mos)EarliestServiceDevelopablePotential(MWa)Animal manure energy recovery 0.85 10,250 75% $5000 $45 $15 -- $17 1.9% 12/12 2012 50 - 110Landfill gas energy recovery 2x 1.6/unit 10,060 85% $2350 $26 $19-- $17 1.9% 18/15 2012 70Waste water energy recovery 0.85 10,250 85% $5000 $40 $30 -- $17 1.9% 18/15 2012 7 - 14Woody residue - Greenfield, noCHP25 15,5004680% $4000 $180 $3.70 -- $17 1.9% 24/24 2014 665Woody residue - Brownfield, CHP 25 19,3004780% $3000 $194 $0.73 -- $17 1.9% 24/24 2014 Not separatelyestimatedGeothermal - binary 3x13/unit 28,500 90% $4800 $175 $4.50 -- $17 1.9% 36/36 2017 375Hydropower - new 10 -- 50% $3000 $90 Incl in fixed -- $17 1.9% 48/24 2016 100’sSolar - CSP (NV > ID) 100 -- 36% $4700 $60 $1.00 -- $102 4.0% 24/24 2015 530/500kV cktSolar - CSP (NV > OR/WA) 100 -- 36% $4700 $60 $1.00 -- $189 6.5% 24/24 2015 530/500kV cktSolar - Tracking PV 20 -- S. ID - 26%MT - 25%OR - 25%E. WA - 24%$9000 $36 Incl in fixed $7.98 $17 1.9% 12/24 2013 Ltd byintegrationcapabilitySolar - Tracking PV (NV) 20 -- 30% $9000 $36 Inclin fixed $7.98 $96 4.0% 12/24 2015 435/500kV cktWind (ID Local) 100 -- 30% $2100 $40 $2.00 $7.98 $17 1.9% 18/15 2013 215Wind (MT Local) 100 -- 38% $2100 $40 $2.00 $7.98 $17 1.9% 18/15 2013 80Wind (OR/WA Local) 100 -- 32% $2100 $40 $2.00 $7.98 $17 1.9% 18/15 2013 1410Wind (AB > OR/WA) 100 -- 38% $2100 $40 $2.00 $7.98 $179 4.3% 18/15 2015 570/500kV cktWind (MT > ID) 100 -- 38% $2100 $40 $2.00 $7.98 $104 4.2% 18/15 2015 570/500kV cktWind (MT > OR/WA) 100 -- 38% $2100 $40 $2.00 $7.98 $198 6.4% 18/15 2015 570/500kV cktWind (MT > OR/WA via CTS) 100 -- 38% $2100 $40 $2.00 $7.98 $120 10% 18/15 2015 244/500kV cktWind (WY > ID) 100 -- 38% $2100 $40 $2.00 $7.98 $120 4.5% 18/15 2015 570/500kV cktWind (WY > OR/WA) 100 -- 38% $2100 $40 $2.00 $7.98 $219 7.0% 18/15 2015 570/500kV cktWaste heat recovery 5 38,000 80% $3500 Incl invar. $8.00 -- $17 1.9% 24/24 2014 10’s - 100’sCoal - Supercritical steam 450 9000 85%$3500 $60 $2.75 -- $17 1.9% 36/48 2017 --Coal - Ultra-Supercritical steam 450 8010 85%$3570 $60 $2.75 -- $17 1.9% 36/48 2017 --Coal - USC steam w/90% CSS 450 10,170 85%$5495 $128 $5.85 -- $17 1.9% 36/48 2023 --Coal - IGCC 623 8680 80% $3600 $45 $6.30 -- $17 1.9% 36/48 2017 --Coal - IGCC w/88% CSS 518 10760 80% $4800 $60 $8.50 -- $17 1.9% 36/48 2023 --NG - Frame gas turbine 85 11960 91% $610 $11 $1.00 -- $17 1.9% 18/15 2012 --NG - Aero gas turbine 2 x 47/unit 9370 91% $1050 $13 $4.00 -- $17 1.9% 18/15 2012 --NG - Intercooled gas turbine 99 8870 91% $1130 $8 $5.00 -- $17 1.9% 18/15 2012 --NG - Reciprocating engine plant 12 x 8.3/unit 885093% $1150 $13 $10.00 -- $17 1.9% 18/15 2012 --NG - Combined-cycle Baseload - 390Peak incr - 25Baseload - 6930Pk incr - 950089% $1120 $14 $1.70 -- $17 1.9% 24/30 2014 --Nuclear 1117 10,400 90% $5500 $90 $1.00 -- $17 1.9% 48/72 2023 --44Combined operating cost of local (in-region) transmission plusconstruction and operating costof transmission (if any) to access remote resources, expressedas a fixed O&M cost. Excludes the $1.00/MWh variable O&M cost of local transmission which should be added to all estimates.45Combined local (in-region) transmission losses plus losses associated with transmission (if any) to access remote resources.46Full plant heat rate.47Full plant heat rate.Sixth Northwest Conservation and Electric Power Plan 

# Chapter 7: Transmission

Summary of Key Findings........................................................................................................ ...... 1 Background..................................................................................................................... ................ 1 Northwest Transmission Planning ................................................................................................ .. 6



## SUMMARY OF KEY FINDINGS

For a number of years leading up to the Fifth Power Plan (May 2005), th ere was concern that there had been little progress on addressing the developing tran smission issues in the region, both in operating the existing system and in pl anning for new major transmission lines. Since then, there has been significant progress in bot h areas. The Western Electricity Coordinating Council (WECC) has created two new reliability coordination centers in the West with new operating tools, which they share with the inte rconnection’s balancing au thorities, to address operational reliability issues. Other operati ng challenges posed by the large increase in wind generation in the region and in the West are being addressed as well. That issue is explored in more depth in Chapter 12.

On the planning side, there have been major cha nges and significant prog ress in the last five years. Both regional and WECC-wide organiza tions have been created and are producing or developing plans or system assessments, partly in response to the needs of their members and partly in response to increased federal interest in transmission planning and development. A number of new projects are in the development and study stage, sponsored by utility members of the two regional planning groups, ColumbiaGr id and Northern Tier Transmission Group (NTTG), and by merchant developers.

On a case-by-case basis, the Federal Energy Re gulatory Commission (FERC) is reviewing and modifying its financing and study process requirements, and the Bonneville Power Administration has taken advantage of this to propose a useful new approach to financing
transmission for access to wind resources. Curr ently proposed legisla tion in Congress would increase the federal backstop siti ng authority that already exists in the Energy Policy Act of 2005 for projects that are supported by regional and interconnection-wide planning efforts.

Nonetheless, for the most part the region’s utilities are ju st getting to the stage when they have to address siting and construction of the projects that have been planned. Siting can present significant difficulties. Siting also can present ch allenges for utilities that may be depending on getting projects built on time, if th ere are delays. The utilities may be forced to rely on backstop plans in order to assure themselves of meeti ng their loads reliably. The Council supports and encourages regional transmission planning efforts, recognizing th at new transmission investment can be key both to maintaining reliable load se rvice and to bringing new renewable resources in to meet regional loads.



## BACKGROUND

The regional transmission system is an integral part of the regional power system. It functions roughly like the highway system, allowing power to flow from ge nerators all across the region (and outside the region in the rest of the Wester n Interconnection) to lo ads. Figure 7-1 belowChapter 7: Transmission Sixth Power Plan

7-2 shows a schematic of the entire Western high-vo ltage transmission system , which is operated in a coordinated fashion in order to maintain syst em reliability although it is constructed and built by individual utilities to meet their own needs. As can be seen from the map, the Northwest transmission system is closely integrated into the overall western system. The colors highlight the systems of the two Northwest subregional planning groups described below, ColumbiaGrid and Northern Tier Transmission Group.

Figure 7-1: Major Western Transmission

Despite the similarities, the transmission system differs from a highway system in key ways. When the highway system gets overloaded, traffic slows down or stops at one point or another. These conditions can persist for hours until the tr affic volume drops down, as for instance, when
an extended rush hour is over.

In the electric transmission system, however, the system is not actually a llowed to get overloaded in normal circumstances, and in the case of an outa ge, either of a generato r or of part of the transmission system, overloads are allowed to persist for only very short periods of time. Moreover, the amount of the allowed overload is limited by constraints on the amount of power that can be allowed to be generated and flow over the transmission lines (“scheduled”), in normal, non-outage, conditions.Chapter 7: Transmission Sixth Power Plan

7-3 This is done for reliability reasons because serious overloads will of ten lead to automatic load or generation disconnections that can in turn lead to wider, uncontrolled casc ading losses of load,
like the 2003 Northeastern blackou t. Overloads can be created almost instantaneously by sudden generation or transmission outages. The limits th at require these operator or automatic actions are set by transmission operators according to standards of the North American Electric Reliability Corporation (NERC) and the Wester n Electricity Coordinati ng Council (WECC) and are based on extensive computer simulations by syst em planners and operators of the behavior of the transmission system under many different op erating conditions. Margins for reliable operation are built into operating standards, so th at the system does not collapse when there is a sudden outage on the system. The operating sta ndards may require that transmission schedules be cut in the event of a system outage in order to bring power flows and other system parameters within the acceptable limits of the reduced system.

Operating limits are set for and managed by syst em operators at a number of points or paths on the system. Figure 7-2 below shows the locations of the major constrained paths in the western transmission system. A path can of ten consist of several lines or se ts of lines in parallel to each other (several examples of this occur in the Nort hwest, e.g. the “North of John Day” path). Most of the paths in the Northwest are constrained, in the sense that there is little to no capacity
available to sell and under cert ain operating conditions they n eed to be monitored by system operators to ensure they do not exceed system operating limits. West of Hatwai, however, in the Spokane area is an example of a path that wa s upgraded by additional line construction several

years ago.Chapter 7: Transmission Sixth Power Plan

7-4 Figure 7-2: Western Constrained Paths

Reno-Alturas COI NW to Idaho West of MCNary
Cross
Cascades
South Cross Cascades
North

North of John Day North of

Hanford West of
Hatwai Nor thwest to Canada

PDCI Monroe-Echo Lake

Paul-Raver

Paul-Allston

Allston-Keeler Montana to NW

West of Broadview

West of Colstrip

Midway-Los Banos Idaho-Sierra Borah West Idaho-Montana

Bridger West

Path C

Southwest
of Four
Corners Northern-Southern

California IPP DCIntermountainMona TOT 1A

TOT 2A Bonanza

West

TOT 2C TOT 3 TOT 4A TOT 4B

TOT 5

SDG&E-Comision
Federal de
Electicidad WOR

EOR

Cholla-Pinnacle Peak Montana
Southease A l be r ta - B C

When the loading on an individual path, cont rolled by individual balancing authorities in coordination with their neighbors (see Chapter 12 for more details on what balancing authorities do) reaches these predefined limits, operators do not allow additional transactions to be scheduled. The system can be said to be congested at that point, though it is not overloaded, but is operating normally.

Congestion can occur in a l onger-term time frame as well. The amount of long-term
transmission service that can be sold in adva nce is limited so that th e total amount sold can actually be scheduled within the reliability limits . This case, when there is no more availableChapter 7: Transmission Sixth Power Plan

7-5 transmission capacity (ATC), is also a form of congestion, even though it does not necessarily lead to a congested operating condition if all of the transmission service that has been sold is not used fully at the same time.

The transmission system is built and upgraded incrementally to meet projected service requirements, so that new service for new lo ads or from new generation can be accommodated within reliable operating limits. Relieving congestion can be costl y. Because of the high cost of transmission system upgrades (as a general a pproximation, 500 kilovolt transmission lines can cost in the range of $2-$3 million per mile to co nstruct, depending on the terrain and land use), transmission is not constructed speculatively. It is constructed to meet forecast native load service requirements and to meet speci fic service requests from third parties 1 like independent generators or parties wishing to wheel power ac ross a utility’s transmission system to a load
outside it.

The high cost of expanding the transmission system , particularly with long, high voltage lines
and intermediate substations means that some congestion on the system, either on an operating basis or as shown by the absence of ATC for sale , may be an economically appropriate result. This is generally not the case for congestion that could impact reliable load service, but could be for projects designed to access chea per or alternative energy supplie s in order to reduce operating

costs.

Transmission system improvements range from lowe r-voltage upgrades that may be part of an ongoing system-upgrade process at a utility to majo r high-voltage projects that can cost hundreds of millions of dollars and take five or more year s to plan and construct. Typically the former do not get as much attention, as they cost less, ar e done on a more routine basis, and depend more on local conditions and requireme nts, though some higher-voltage local projects or those in sensitive areas can be expensive and difficult to site and can be subject to uncertainty. The latter, however, because of their cost and land-use impacts can get considerable attention.

For a number of years leading up to the Fifth Po wer Plan, there was little major transmission project development, although there continued to be upgrades to m eet local reliability needs. Partly this was a result of the ability to site natural gas generation closer to load centers and with a smaller requirement for transmission. Howeve r, when the Council developed the Fifth Power Plan, there was reason to be concerned about th e transmission system. There had been some progress on improving the operation of the transm ission system to allow better use of limited existing capacity by implementing remedial actio n schemes (RAS), but there had been little activity in planning for major transmission system expansion. The regional transmission system was being loaded closer a nd closer to capacity.

These problems are now being addressed. There have been important changes in operations though WECC’s creation of two new reliability coordination center s in the West and funding of new software that gives the reli ability coordinators and the West ’s balancing authorities clearer
and more current information on the instantane ous state of the system. Other operational changes are being considered and implemented in la rge part because of the pressure to integrate

1 These third-party service requests ar e governed by the FERC Open Acces s Transmission Tariff (OATT). The OATT specifies the study procedures and financial circum stances under which the transmission owner must respond to third-party service requests.Chapter 7: Transmission Sixth Power Plan

7-6 large amounts of variable generation, primarily wind. The operational ch anges related to wind integration are discussed in Chapter 12.

On the transmission-planning side, two subregio nal planning groups, Colu mbiaGrid, centered on Bonneville and the Washington utilities, a nd Northern Tier Transmission Group, focused primarily on the east side of the region, have been formed and are conducting planning studies and coordinating transmission deve lopment efforts across the Northw est. They are also jointly leading efforts to address some of the opera tional changes mentioned above and described further in Chapter 12.

In addition, the Transmission Expansion Planning Policy Committee (TEPPC) has been formed by WECC to develop West-wide commercial tr ansmission expansion planning studies and coordinate and provide informa tion to subregional planning e fforts. Finally, a number of projects are being proposed by both utilities and merchant develope rs, largely in response to the state RPS requirements and increasing emphasis on reducing carbon emissions across the West.

There has also been a significant increase in inte rest in transmission planning and siting at the federal level. In the Energy Policy Act of 2005, the federal Department of Energy (DOE) was required to conduct triennial transmission-conges tion studies and allowed to designate National Interest Electric Transmission Corridors, a nd FERC was given a backstop siting role for transmission proposals in those co rridors for which state siting aut horities did not act promptly. At the time the Council adopted the Sixth Power Plan, Congress was considering energy legislation. The House of Representatives passe d the American Clean Energy and Security Act of 2009 (know as the Waxman-Markey bill, for its sponsors) in June of that year. The bill contained provisions for regional transmission planning entities to submit plans to FERC, and gave FERC additional backstop si ting authority in the Western Interconnection for projects vetted through and supported by a regional transmission plan.

The American Recovery and Reinvestment Act (ARRA) provided DOE with funding for technical support of interconnec tion-based transmission plans, including support for state and relevant non-governmental organizations to par ticipate, as well as support for state resourceplanning efforts. WECC, through TEPPC, worked with the Western Governors’ Association (WGA) to develop an application for funding, wh ich was successful. Some of the WGA funding will be used to support completion of the West ern Renewable Energy Zone (WREZ) project, which will help coordinate state and utility e fforts to target specific areas for renewable development, along with the necessary transmission corridors. This is intended to provide basic input information into the TEPPC transmission planning effort.



## NORTHWEST TRANSMISSION PLANNING

ColumbiaGrid, formed in 2006, along with its members develops a system assessment and biennial transmission plan for its members. It finished its first bienni al plan in 2008, which was approved by its board of directors and published in February 2009. It has recently published a draft 2009 system assessment, highlighting the areas in its members’ systems that need to be addressed, either by the individual owners, or in the case of issues involving several owners, by a ColumbiaGrid study team. Joint study teams are al so formed to address issues and projects that overlap between ColumbiaGrid and adjacent planning groups like NTTG.Chapter 7: Transmission Sixth Power Plan

7-7 This current draft system assessment identified a number of potential reliability issues over the next five and 10 years that would need to be addressed by the transmis sion owners, ranging from relatively local issues such as service in the Olympic Peninsula over the 115-kilovolt system up
to wider-scale issues such as se rvice over the 500-k ilovolt West of Cascades paths to loads in the I-5 corridor main grid. The transmission owners have identified potential mitigation projects for a number of these issues, which will be studied fu rther in the ColumbiaGrid biennial plan. The main projects studied are shown on Figure 7-3 below. The underlying transmission system shown on the map comprises the facilities of ColumbiaGrid me mbers. The Hemmingway - Boardman project is also in the study set, although its s ponsor, Idaho Power, is not a
ColumbiaGrid member.

Figure 7-3: ColumbiaGrid 2009 Syst em Assessment - Projects Studied

Source: ColumbiaGrid

Bonneville, which is a member of ColumbiaGr id, has developed an innovative approach to identifying transmission development to provide long-term firm transmission service, which is particularly helpful for disperse d generation projects like wind farms. The first use of this network-open-season approach was in 2008, and a second open season was conducted in 2009. The Bonneville approach, approved by FERC, provi des for a cluster study of requests in the transmission-service request queue, an offer of service at embedded-cost rates with Bonneville providing the financing (to be recovered through wheeling rates when service commences), and reordering of the queue positions for those requesto rs not willing to commit to take service with the proposed transmission project. This appr oach was very successful in 2008 and led to
Bonneville’s determination to move forward with several major transmission projects, including the West of McNary project and the I-5 corrid or reinforcement project. Bonneville also wasChapter 7: Transmission Sixth Power Plan

7-8 aided in the ability to finance these projects by the availability of federal economic-stimulus funding, which provided increased borrowing author ity and allowed Bonneville to ramp up its capital-expenditures program.

This approach improves the default process, required by the FERC OAT T, which both requires that service requests be studied in the order in which they were received and puts the financing burden primarily on the entity requesting transmissi on service. Both of these conditions served as significant impediments to development of larg e transmission projects to serve a number of smaller wind developments.

Bonneville’s approach is one of several modifi cations to the OATT approach to financing new transmission for renewables that FERC approve d. In a 2007 order on the California ISO, FERC
allowed modifications to OATT fi nancing requirements for a renewa ble collector project in the Tehachapi area of Southern California. In October 2008, FERC allowed an incentive rate of return on PacifiCorp’s Energy Gateway projects (described below), taking into account their ability to move large amounts of renewable energy to load centers. In March 2009, FERC
conducted a technical conference on integrating renewable resource s into the transmission grid, which may result in modifications to the OATT itself, building on the case-by-case approach employed so far. The Council supports actions su ch as these to enhance the ability of the transmission system to support renewables and robust markets.

Northern Tier Transmission Group, formed in 2007, focuses its efforts on larger transmission projects that move power acros s its footprint, and connect w ith adjacent sub-regional groups’ footprints (ColumbiaGrid and WestConnect). Lo wer-voltage, more local projects are addressed by the individual NTTG transmission-owning memb ers. NTTG members have proposed a set of primarily 345-kilovolt and 500-kilo volt projects to meet native load service and transmission service requests under the OATT from potential exporters from th e NTTG footprint. These projects are shown on Figure 7-4 below.Chapter 7: Transmission Sixth Power Plan

7-9 Figure 7-4: NTTG Propos ed Transmission Projects

Source: NTTG

The Transmission Coordination Work Group or TCWG (composed of PGE, Avista, Idaho Power, PacifiCorp, Pacific Gas and Electric, TransCanada, Sea Breeze Pacific-RTS, and Bonneville) is sponsoring a project-review proc ess to examine potential interactions among various major project proposals that connect with or pass though the McNary area of Northeastern Oregon. The examination of projec t interactions is a fundamental part of the process of getting an approve d rating for a project under WECC procedures. The rating is a foundational part of the determination of reliabl e operating limits for transmission lines and paths.

The map in Figure 7-5 below shows projects sponsored by Columbia Grid members, like Bonneville’s West of McNary and I-5 Corridor projects, those sponsored by NTTG members, like the Gateway, Hemmingway - Boardman, Hemmingway - Captain Jack, and Southern Crossing projects, and those sponsored by others , like TransCanada’s Northern Lights, PG&E’s Canada - California project, and the Sea Breeze cable projects. Th ere is some overlap between what is shown on Figure 7-4 and Figure 7-5. Mona Windstar Townsend

MidpointBoardmanHemingway

Idaho Power

Terminal A eolus

Bridger Cedar Hill Borah

Crystal Sand Hollow Wyodak

UTAH NEVADA IDAHO WYOMING

OREGON

CALIFORNIA MONTANA WASHINGTON

ARIZON A NEW MEXICO COLORADO

Red Butte Sigurd Gateway West

PacifiCorp Idaho Power
Populus Sheridan Dry Fork
Hughes

Carr Draw Mid-Columbia

HemingwayCaptain Jack

PacifiCorp Southern Crossing

Portland General Walla Walla Wallula McNary

Near Dave Johnston Near Boardman

Olallie Bethel

Round Butte

Gateway

South

PacifiCorp Gateway

Central

PacifiCorp Mountain

States Intertie

NorthWestern Energy

Captain Jack

Le g end

230 kV

230 kV Double Circuit

345 kV

345 kV Double Circuit

500 kV

500 kV Double Circuit Hughes Transmission Project

Basin Electric Black Hills Power & Light

HemingwayChapter 7: Transmission Sixth Power Plan

7-10 Figure 7-5: Major Northwest Projects

Source: ColumbiaGrid

Although there has been a subs tantial improvement in coordinated regional transmission planning and development over the period since th e Fifth Power Plan, some utilities still face difficulties in getting transmission access to market hubs and to resources they are planning on to
meet future loads or to meet their transmissi on-service obligations to generators under their OATTs. Even the projects that are farthest along in developm ent, like Bonneville’s West of McNary project, have not yet surm ounted all the possible problems on the path to completion.

Whether this situation comes from difficulties in siting large transmission lines or from the planning process itself taking longe r than anticipated, it can leav e utilities in the position of having to acquire back-stop resources to make up for those that they were not able to access reliably due to transmission limitations. The C ouncil recognizes that this can also lead to differences in resource timing and acquisition strategy from t hose described for the overall region in the power plan. The inability to site needed transmission can also force utilities to
make less-desirable resource choices than mi ght otherwise be made, by precluding access to distant renewables and to regional and other ma rkets. The Council supports and encourages regional transmission planning effo rts, recognizing that new transmission investment can be key both to maintaining reliable load service and to bringing in new renewa ble resources to meet regional loads.Sixth Northwest Conservation and Electric Power Plan 

# Chapter 8: Direct Use of Natural Gas

The Policy Question............................................................................................................ ............ 1 Current Council Policy on the Direct Use of Gas....................................................................... 1 Analysis of the Direct Use of Natu ral Gas for the Sixth Power Plan ......................................... 3



## THE POLICY QUESTION

The appropriate role for the Council in promoti ng the direct use of natural gas for space and water heating has long been an i ssue in the region. The Council has analyzed the technical and the policy issues in a number of studies dating back to its very first power plan. While the specific issues have changed somewhat ove r time, three central questions remain:

1. Is the conversion from electric ity to natural gas for resident ial space and water heating a
lower-cost and lower-risk alternative for meeting the region’s load growth when compared to other options?

2. If so, how much cost-effec tive “fuel-switching” potential is there in the region?

3. Are fuel-choice markets working adequately?

During development of the sixth plan, a fourth question arose: How does the conversion from electricity to natural gas for space and water heating impact the region’s carbon emissions?



## Current Council Policy on the Direct Use of Gas

The Council’s current policy on the di rect use of natural gas is stated in the text box below. This policy was adopted with the Council’s Fourth Po wer Plan following a detailed analysis of fuelconversion potential and cost in 1994. 1 The policy was reaffirmed in the Council’s Fifth Power
Plan. 2

1 Northwest Power Planning Council. Fourth Northwest Conservation and Electric Power Plan. March 1996 (96-5). Pages 4-10,11.

2 Pacific Northwest Power and Conservation Council. Fifth Northwest Electric Power and Conservation Plan. May 2005 (2005-7). Pages 3-45.Chapter 8: Direct Use of Na tural Gas Sixth Power Plan

8-2 The Council has not included programs in its power plans to encourage the direct use of natural gas, or to promote conversion of electric space and water heat to natural gas. This policy is consistent with the Council’s view of its legal mandate. In addition, the Council’s analysis has indicated that fuel-choice markets are working we ll. Since the large electricity price increases around 1980, the electric space-heating share has st opped growing in the region while the natural gas space-heating share in existing homes increased from 26 percent to 37 percent. A survey of new residential buildings conducted in 2004 for the Northwest Energy E fficiency Alliance found that nearly all new single-fam ily homes constructed where natural gas was available had gasfired, forced-air heating systems. 3 The survey also found an incr eased penetration of natural gas heating in the traditionally electric-heat-dominated multi-family market, especially in larger units and in Washington. 4 Fuel conversion of existing houses to natural gas has been an active market as well, often promoted by dual-fuel utilities.

The Council policy on fuel choice has consistently been that fuel conversions, while they do reduce electricity use, are not conservation unde r the Northwest Power Act because they do not
constitute a more efficient use of electricit y. However, the Council’s analysis also has recognized that in some cases it is more economi cally efficient, and bene ficial to the region and individual customers, to use natural gas dire ctly for space and water heating than to use electricity generated by a gas-fired generator. However, this is very case-specific and depends on a number of factors including th e proximity of natural gas di stribution lines, the size and structure of the house, the climat e and heating requirements in th e area, and the desire for air conditioning and suitability for heat pump applications. In general, although direct use of natural gas is more thermodynamically efficient (except for the case of heat pumps), it is more costly to purchase and install. Th erefore, its economic advantage depe nds on the ability to save enough in energy costs to pay for the higher initial cost.

3 Northwest Energy Efficiency Alliance. “Single-Fa mily Residential New Construction Characteristics and Practices.” Portland, OR, March 27, 2007. Prepared by RLW Analytics.
4 Northwest Energy Efficiency Allia nce. “Multi-Family Residential New Construction Characteristics and Practices.” Portland, OR, June 14, 2007. Prepared by RLW Analytics. Council Policy Statement

The Council recognizes that there are applications in which it is more energy efficient to use natural gas directly than to generate elec tricity from natural gas and then use the electricity in the end-use application. The Council also rec ognizes that in many cases the di rect use of natural gas can be more economically efficient. These potentially co st-effective reductions in electricity use, while
not defined as conservation in the sense the Counc il uses the term, are nevertheless alternatives to be considered in planning for future electricity requirements.

The changing nature of energy markets, the subs tantial benefits that can accrue from healthy competition among natural gas, electricity, and other fuels, and the desire to preserve individual energy source choices all support the Council taking a market-oriented appr oach to encouraging efficient fuel decisions in the region.Chapter 8: Direct Use of Na tural Gas Sixth Power Plan

8-3 

## Analysis of the Direct Use of Na tural Gas for the Sixth Power Plan

In 1994, the Council analyzed the economic efficien cy of converting existing residential electric space and water heating systems to gas systems. 5 The results of that st udy showed there were many cost-effective fuel-switching opportunities within the region, repr esenting a potential savings of over 730 average megawatts. As stat ed above, the market, w ith its high rate of conversions from electric to gas systems, was performing many of the conversions on its own. Consequently, the Council has no t included fuel switching or fu el-choice measures in its subsequent power plans.

With the financial support and cooperation of the Northwest Gas Association and Puget Sound Energy, the Council, working through its Region al Technical Forum, is conducting an updated economic analysis of fuel conversion for resi dential space and water heating equipment in existing homes and fuel choice for residential space and water heating equipment in new homes in the Pacific Northwest. While the study resu lts were not available at the time the Council adopted the Sixth Power Plan, it is possible to forecast potential im plications. Should the direct use of natural gas prove to be a lower-cost a nd lower-risk alternative for meeting the region’s load growth, including potentia l cost and risk from carbon emi ssions, the Council will need to assess whether the fuel-choice markets are working adequately. If the markets appear to be working adequately -- i.e, consumers are selec ting natural gas for space and water heating where
it makes economic sense -- then the Council will re tain its current policy, which leaves the choice of heating fuels to indi vidual consumers. If however , the market is not working adequately, the Council may decide to make sp ecific recommendations in the future including but not limited to providing information and promoting efficient pr icing of electricity.

The Council’s objective for this analysis is to recr eate its 1994 study with up-to-date information. The scope of the analysis has been expanded to include new construction for single-family dwellings and both new construction and existing buildings for multi-family dwellings. The updated analysis is also testing the cost, ris k, and carbon-emissions impact of converting from natural gas to electricity as well as conversions from electr icity to natural gas. A major difference between the Council’s 1994 study a nd the current analysis is that all direct use of natural gas alternatives will be modeled as “resources” directly in the Council’s portfolio model. This will allow the Council to directly co mpare the cost and risk associated with meeting regional electricity loads with conservation and traditional generating re sources (including those fired by natural gas) against meeting those same n eeds by using natural gas di rectly in the home.

Multiple space and water-heating technologies are being considered in the analysis. Individual
residential customers have different combina tions of these technologies. In addition, each customer has a number of technology options fr om which to choose when existing equipment fails and needs to be replaced. This analysis assumes that customers install new equipment only when existing equipment needs to be replaced beca use it has come to the end of its useful life. At that time, customers can install the same type of equipment they already have or install a different technology. In new cons truction, the customer has the choice of all technologies and energy sources, but once that choice is made, they must live with it for the life of the equipment.

5 Northwest Power Planning Council. “Direct Use of Natura l Gas: Analysis and Policy Options”. Issue Paper 94-41. Portland, OR. August 11, 1994.Chapter 8: Direct Use of Na tural Gas Sixth Power Plan

8-4 For example, in one identified market segment, the home has an electric forced-air furnace (FAF) for space heating and an electric-resistance water heater. This study assumes that when the electric FAF fails, it could be replaced with a gas FAF, a gas/heat pump hybrid, or a gas hydronic system. Likewise, when the electric-resis tance water heater fails it could be replaced with the same type of water heater, a gas tank wate r heater, or an instantane ous gas water heater.

In this study each market segment consists of ju st one type of equipment for replacement of the failed existing equipment. Therefore, one market segment would include a gas FAF and a gas tank water heater as the retrofit equipment options for the electric FAF system and the electric resistance water heater, while another market segment would specify another combination of technologies.

Each of these technology choices comes at a cost to not only the individual customer, but more importantly, the entire region. Consistent with the Council’s other anal ysis, this analysis accounts for both the money spent by customers to install a different type of new equipment and the resulting impact on natura l gas or electricity consump tion, changes in operations, and maintenance costs and changes in greenhouse-gas emissions.

The economics of these technology c hoices are highly dependent on th e relative costs of natural gas and electricity and the capital cost of conversion. To addre ss the wide range of conversion costs faced by consumers, a “Monte Carlo” model was developed similar to that used in the 1994 Council analysis. The flowchart in Figure 8-1 i llustrates the six-step “Monte Carlo” process being used in this economic analysis. In Step One, the model designates one of the 91 market segments (inputs) for the analysis. Of the 91 inputs, 49 are stochastic, meaning they are randomly selected. In Step Two, the values for the 49 stochastic inputs ar e selected. In Step Three, values for four of the stochastic inputs are established by regressi on equations. In Step Four, the 49 stochastic inputs, the four regression inputs, 29 deterministic (fixed) inputs, and two decision inputs (marginal cost of electricity and marginal co st of gas) are accessed by the model’s equations. After the completion of the calculations, the values for key outputs are displayed for summary viewing in Step Five. In Step Six, steps two through five are repeated as the model performs all the necessary calculations 1,000 times for each of the 91 market segments and for each of the 525 combinations of margin al electric and marginal gas costs.

A complete description of th e direct use of natural gas economic model and the input assumptions used in the model are availabl e on the Regional Technical Forum’s website: http://www.nwcouncil.org/energy/rtf/ studies/rfp/directuse/GEPReport.pdf

.Chapter 8: Direct Use of Na tural Gas Sixth Power Plan

8-5 Figure 8-1: Economic Analysis Process

Once the Monte Carlo model has identified the most economical market choices for fixed combinations of natural gas and el ectricity prices this information will be fed into the Regional Portfolio Model (RPM). The RPM will then be used to test the economics of each technology choice over the wide range of future natural gas a nd electricity price combinations. This analysis
will seek to determine whether across the entire ra nge of electric and gas cost combinations there are conversions to natural gas that are economically efficient and wh ich result in lower risk to the region’s power system.

The Council was unable to complete the RPM an alysis of the economics and emissions impacts of the direct use of natural gas prior to the release of the Sixth Power Plan. Due to the significant regional interest in this analysis, the Council believes it should provide adequate opportunity for review and comment on the input assumptions an d results of this work before considering changes to its current policy. Therefore, the Co uncil included a specific ta sk in the action plan (ANLYS-16) to complete this analysis during th e first six months of 2010 and to consider any policy changes and action items related to the findings.Sixth Northwest Conservation and Electric Power Plan 

# Chapter 9: Developing a Resource Strategy

Introduction................................................................................................................... .................. 1 Developing a Resource Strategy................................................................................................. .... 2 Resource Strategy is Tied to the Act........................................................................................... 2
Portfolio Selection ............................................................................................................ .......... 4
Model Portfolios ............................................................................................................... .......... 7 Interpreting Portfolio Costs................................................................................................... .. 8
Low-Risk Portfolios............................................................................................................ .... 9 Interpreting Carbon Emissions and Costs............................................................................. 10 Sources of Uncertainty......................................................................................................... ......... 11
Wholesale Power Prices......................................................................................................... ... 11 Load Uncertainty ............................................................................................................... ....... 13
Fuel Prices.................................................................................................................... ............. 13 Hydropower Generation.......................................................................................................... .. 14
Resource Construction Costs .................................................................................................... 14 Climate Change and Carbon Emission Goals........................................................................... 16 Plant Availability ............................................................................................................. ......... 18 Renewable Energy Production Incentives ................................................................................ 18 Renewable Energy Credits....................................................................................................... . 19 Other Assumptions.............................................................................................................. .......... 19 Existing Renewable Portfolio Standard Resources................................................................... 20 Forced-in Renewable Portfolio Standard (RPS) Requirements................................................ 22 Conservation from New Program s, Codes, and Standards....................................................... 23 Independent Power Producer s’ (IPP) Resources ...................................................................... 24 New Generating Resource Options........................................................................................... 24 System Flexibility and Capacity Requirements........................................................................ 25



## INTRODUCTION

This chapter describes the Council’s treatment of ri sk in its planning analys is. In particular it describes scenarios that use the Council’s regi onal portfolio model. This computer model simulates the development and operation of the region’s power system in an uncertain world.

The Council’s plans always have recognized unc ertainty. The Fifth Power Plan (May 2005), however, was the first of the Counc il’s plans that used the portfo lio model to analyze strategies
over hundreds of futures.

The chapter describes the model’s approach to ev aluating and selecting port folios. It discusses the interpretation of the results of testing thousands of portfolios against 750 futures. The chapter then describes each of th e sources of uncertainty that ar e included in the portfolio model for the sixth plan. The chapter concludes with a discussion of several issues unrelated to sources of uncertainty, such as how peak-power requireme nts are accounted for in the plan’s analysis.Chapter 9: Developing a Res ource Strategy Sixth Power Plan

9-2 

## DEVELOPING A RESOURCE STRATEGY

Risk assessment has been central to Council pl anning since the first power plan. The Council's resource portfolio and forecasts must, by statute, address regional requirements over the next 20 years. However, reliably forecasting factors on which the plan relies is difficult, if not impossible. Therefore, the Council must assess co st and risk, both to th e power system and to the environment, under significant uncertainty.

Earlier plans looked at an array of uncertainties and sources of ris k. Load uncertainty, fuel price uncertainty, and hydro generation vari ability figured prominently in th e conclusions of the plans. Those plans incorporated gas- and coal-price excu rsions in forecasts and sensitivity analyses. They also considered capability to export and import various amounts of power to and from outside the region. Since the first power plan, th e Council has analyzed the value of shorter lead times and rapid implementation of conservation and renewables. The Council also has valued “optioning” generating resources. Optioning refers to carrying out pre-construc tion activities and then, if necessary, delaying constr uction until conditions favor going ahead.

In the Fifth Power Plan, the Council extended its risk assessment and management capabilities. It developed a computer model that enabled the Council to look at decisions made without the perfect foresight that most models assume. Th e scenarios broadened the scope of uncertainty.
New uncertainties included those associated with electricity market price, aluminum smelter loads, carbon-emission penalties, tax credits, an d renewable energy credits. Scenarios evaluated thousands of resource portfolios and captured the co sts associated with port folios that adapted to changing circumstances and alternative scenarios.

This sixth plan builds on the lessons and techni ques of the fifth plan. Council scenarios now incorporate uncertainty about pow er plant construction costs and availability. Scenarios track carbon production using several ne w techniques, and the impact of carbon penalties moves to center stage. The representa tion of conservation and demand response continues to evolve.

The study and treatment of risk re quires a suitable framework. The next section describes how uncertainty, cost, and risk bear on th e selection of a resource portfolio.



## Resource Strategy is Tied to the Act

The Council’s Power Plan identifies resource stra tegies that minimize the expected cost of the region’s electricity future. The Act calls for a plan that assures an “adequate, efficient, economical, and reliable” power supply. Effici ent and economical are interpreted to mean economically efficient, and net present-value (NPV) system cost is arguably the best indicator of such efficiency.

The Council’s regional portfolio model (RPM) evaluates possible portf olios under 750 different possible futures. Each future is a distinct combination of conditions for carbon penalties, demand growth, electricity and fu el prices, hydroelectric genera tion, and other key sources of uncertainty. For each future, the values of each variable are specified hourly over the 20 years of
a scenario.Chapter 9: Developing a Res ource Strategy Sixth Power Plan

9-3 The model uses the same set of 750 futures to evaluate each resource portfolio. The model selects a future before it begins its chronological simulation of a given resource portfolio. As the model moves forward through the sc enario, it simulates the behavior and cost of every resource in the regional power system, including new reso urces in the specific po rtfolio being assessed. Once the model completes the last period in the scen ario, it computes the net present value of the costs for that resource portfolio under that future. It then selects a different future and starts over at the beginning of the scenario. Only after a resource portfolio has been evaluated under all 750
futures and a distribution of net present-value cost s has been constructed does the model consider a different resource portfolio.

The expected cost of meeting the region’s require ments gives us an idea of the most likely cost
outcome. Most futures will cluster around this value. Comparing average net present-value system costs gives us an indication of which portfolio is most likely to achieve the Act’s goal of an economically efficient system.

Special care is exercised in using the expected costs from this model, however. The section below, Interpreting Portfolio Costs , discusses this issue in more detail.

A “good” resource plan, according to the Act, is one that is economically efficient and has low net present value. But a plan ce rtainly would be considered unsu ccessful if it failed to meet the other requirements of the Act, adequacy and re liability. Consequentl y, the Council’s regional portfolio model screens out resour ce portfolios that do not prove adequate and reliable. That leaves, however, very many portfolios, including one s that are overbuilt and quite expensive. It stands to reason that a portfolio that met the ot her requirements of the Power Act still would be
considered unsuccessful if it resulted in a high net present-value cost to the region.

Knowing that forecasts will be wrong and that the future that actually unfolds may be among those in which our plan performs poorly, what is the be st course of action? Ultimately, there is only one irreversible set of conditions. Risk-averse decision-makers will try to find portfolios that minimize the chance of high costs.

One approach to finding such a resource portfolio is to test portfolios under many distinct,
feasible conditions and note the worst outcomes fo r each resource portfolio. Different resource plans, after all, will pe rform poorly under different circumstances. However, the worst outcome is not a good risk measure because its cost can be limitless. The “likely” of the worst outcomes is better behaved. These ideas and concepts are reflected in the Council’s risk measure.

The Council’s risk measure, TailVaR 90 , is the average of the hi ghest 10 percent of the net present-value cost outcomes associated with a given portfolio across the 750 futures. To the extent the Council wants to minimize the likely cost of the future energy system and is indifferent to risk, it would pref er a resource portfolio that minimizes expected or average cost.
To extent the Council is risk aver se, it would tend to select a resource portfolio that may have higher expected cost but lower risk.

Using these definitions of cost and risk, therefore, maximizes the chance of identifying portfolios that achieve the Act’s objectives . Such a resource portfolio is likely to be lowest-cost among those that minimize the chance of high power costs, even under the worst circumstances.Chapter 9: Developing a Res ource Strategy Sixth Power Plan

9-4 

## Portfolio Selection

To understand the Council’s approach requires a lit tle background. It is useful to expand on the concepts introduced in the previous section. Some familiarity with the m eaning of several terms, as the Council uses them, is also helpful.

A future is a specific combination of values for uncer tain variables, specified hourly over the 20- year planning period. For the Council’s work, a future will be a specific sequence of hourly values for each uncertainty. A future is hourly electricity requirements for 20 years, combined with hourly electricity prices fo r 20 years, combined with hourly (or daily) natural gas prices for 20 years, and so forth. The number of sources of uncertainty consider ed in Council scenarios would render the enumeration here unwieldy, but the next section describes them generally.

Given a particular future, the primary measure of a portfolio is its net present-value total system cost. These costs include all variable costs, such as those for fuel , variable operation and maintenance (O&M), and long- and short-term ma rket purchases. These costs also include the
fixed costs associated with investment in new resources and with their operations and maintenance. The present value calculation di scounts these future costs to September of 2009
and states them in constant 2006 dollars. Di scounting and other financial assumptions are discussed in Appendix N of the plan.

The futures differ significantly one from the othe r. While some planners would base future uncertainty on historical patterns, the Council recognizes that future markets and other sources of uncertainty rarely resemble the pa st. Some would refer to a Council future as a scenario. In the Council’s modeling, futures typically include some historically unprecedented paths for prices, loads, and other variables. A small number may have an unlikely but not impossible future
behavior.

The Council’s treatment of uncertain ty also reflects the potential for a larger pool of contributing factors than history provides. The model uses larger variatio n and weaker relationships among sources of uncertainty to achieve this effect . Past relationships often depend on markets, technologies, regulations, and ot her circumstances that could change in the future. The introduction of reserve-margin standards and renewable-portfolio-sta ndard legislation in California, for example, has changed the tradi tional relationship between natural gas price and wholesale electricity price. Over the last 30 years, combined-cycle combustion turbines filled the role of providing new energy and capacity. Fundamental market economics assert that this role imposes a relationship between electricity pr ices and natural gas, th e fuel that combustion turbines burn. Regulatory changes are upsetti ng that relationship. Renewables, built for purposes other than reducing expected cost or making a profit, are displacing combustion turbines. Non-renewable resources, added for reli ability and flexibility, are also contributing. These innovations are changi ng the rules of the market.

Larger variation and weaker relationship among uncertainties in the C ouncil’s model therefore provide an opportunity to better understand the consequences of technological innovation, legislative and regulatory initiatives, transf ormation of markets, and other “unforeseeable” events. Combining futures in unlikely ways, moreover, reveals how different sources of uncertainty can combine to bring extraordinary ri sk. The next section describes the nature of specific sources of uncertainty.Chapter 9: Developing a Res ource Strategy Sixth Power Plan

9-5 The effect of different futures on the cost of a portfolio produces a distribution of portfolio costs.
This distribution is the so urce of expected cost and risk attrib uted to that portfolio. Figure 9-1 represents the number of times the net present va lue cost for a single po rtfolio under all futures fell into specific ranges or “bins.” That is, each bin is a narrow range of net present-value total system costs.

Figure 9-1: Example of a Portfolio Cost Distribution

0 20 40 60 80 100 120 140044,10456,79469,48482,17494,865107,555120,245132,935145,625158,316171,006183,696196,386209,077221,767234,457247,147259,838272,528285,218297,908310,599

$M 2006 PV 2009Frequency

TailV @ R90 Mean

Source: "Costs Illustrated.xls", worksheet "distribution"

Figure 9-1 is an example of the cost distribution for a single resource portfolio. Each resource portfolio will have a distinct dist ribution like the one in the figure.

Because a simulation of a particular resource port folio typically uses 750 futures, the resulting distributions can be complicated. Representative statistics make the task of capturing the nature of a complex distribution manageable.

The average of the distribution provides an idea of the most likely cost outcome for this resource portfolio. Comparing average net present-value sy stem costs between two portfolios gives us an indication of which portfolio is most likely to have the lowest cost.

The measure of risk that the Council adopted is TailVaR 90 . Briefly, TailVaR 90 is the average value for the worst 10 percent of outcomes. 1 It belongs to the class of “coherent” risk measures that possess special properties. These propertie s assure the measure re flects diversification benefits of resources in a portf olio. Coherent measures capture the magnitude and likelihood of

1 See Appendix P of the Fifth Power Plan for a more detailed discussion of this risk measure and a comparison with
other risk measures.Chapter 9: Developing a Res ource Strategy Sixth Power Plan

9-6 bad outcomes, rather than the pred ictability of, or the range of di stribution for, an outcome. As mentioned above, use of TailVaR 90 is also consistent with avoiding high-cost outcomes.

Using these two statistics, each por tfolio is associated with a point on a graph. The horizontal axis measures the portfolio’s cost and the vertical axis measures the portfolio’s risk. This way, a large number of resource portfolios can be compar ed on these two measures . A typical scenario evaluates 2,000 to 5,000 possible port folios. The set of points corre sponding to all portfolios is a feasibility space , an illustration of which appears in Figure 9-2.

For each level of risk, there is a level, horizonta l line passing through the feasibility space. The left-most portfolio in the feasibil ity space on that line is the least-co st portfolio for that level of
risk. The efficient frontier of the feasibility space will contain only least-cost portfolios.

Because the Council typically evalua tes thousands of portfolios, the efficient frontier permits the Council to narrow its search, typically to a fraction of one percent of these portfolios. It does so without invoking weighting factors or other, more problematic schemes that have been used to assess decisions with multiple objectives.

Figure 9-2: Feasibility Space

1 Space of feasible solutionsIncreasing Risk

Increasing Cost E f f i c i e n t F r o n t i e r

Source: Feasibility Space 090724.ppt

The Council’s approach to resource planning co uld be called “risk-constrained, least-cost planning.” Given any level of ri sk tolerance, the efficient fron tier finds portfolios that achieve that level at the lowest cost. In this sense, it is comparable with traditional utility integrated resource plans (IRPs), also referred to as “least-c ost” plans. If risk is ignored, the “least-cost” plan is the upper-left-most portf olio on the efficient frontier.Chapter 9: Developing a Res ource Strategy Sixth Power Plan

9-7 Risk often stems from short-lived events. Agai n, a measure that relies on net present-value costs may miss this kind of risk. Consequently, addi tional study of portfolio behavior over time is necessary. An example of the evaluation of portf olio risk in particular futures appears in Appendix J. The section Low-Risk Portfolios , below, discusses risk in more detail.



## Model Portfolios

The Council’s resource portfolio does not look like a traditional firm resource plan to meet firm electricity demand. For example, it does not co ntain completion dates for new resources that will just meet load growth when needed.

The Council’s definition of a res ource portfolio consists of two elements. For most conventional resources, the portfolio specifi es the option dates for specific types and amounts of generating resources. A resource is optioned when the de sign, siting, and licensing have been completed and it is ready for construction.

The second element of the portfolio consists of policies for conservation and demand response. Policies include cost-effectiveness “adders” or prem iums over wholesale el ectricity market price for conservation acquisitions. For demand response , the policy consists of implementing one of several prescribed schedules for irrigation, heating, cooling, and other programs. These schedules specify the number of megawatts implemented at different times for each program over the 20-year scenario horizon.

The option schedules, conservati on premiums, and demand-respons e deployment schedules for portfolios that lie on the efficien t frontier are determined through a computerized search process. The model initially tries random portfolios, such as one where no resources can be added, one
where all resources are available for construction at their maximum build rate, and so forth. For each of these, performance is simulated under the 750 futures, and the resulting average cost and
risk are observed. After severa l hundred portfolios have been evaluated, the computer discovers which schedules of resources and policy choices tend to lower average cost and risk. By trying modifications of the more successful portfolios, it attempts to minimize the cost of the power system at different levels of risk.

The reason for using a plan defined by earliest co nstruction start dates lies with the nature of generating resource construction ri sk. A significant source of risk to the region arises from
inaccurate forecasts of the need for or the valu e of a generating resource. Both building too few
and too many resources can be expensive and wasteful. The Council’s model re flects the reality
that decision-makers never can be sure how the future will work out.

The opportunity to construct a resource is prescribed by a given resource portfolio. Given such an opportunity, the model makes a decision – in each period of each future – whether to proceed
with construction. This decision to construct is based on what the model thinks about the
eventual value of and need for that resource under that particular future and at that particular time. The model’s decision pays no attention to (does not “know” about) what will unfold in subsequent periods under this future. The model computes requirements and costs chronologically under each future so the model’s decision-making has only a notion of the past. Thus, the decision must be based only on what pri ce and requirement trends have been up to that point.Chapter 9: Developing a Res ource Strategy Sixth Power Plan

9-8 Constructing a plant does not guarantee the plant will be economical. Just as in life, circumstances change without notice. The mode l makes forecasting mistakes in some futures, and the costs – due to delays, emergency purch ases, overruns, shortages, and cancellations – associated with those mistakes are captured in th e portfolio’s net present-value costs. By this means, the model identifies resource portfolios with values that are less sensitive to assumptions
about the future.

The conservation acquired and the generating resour ces constructed in a given portfolio will be
different in each of the 750 futures. The constr uction of generating resources and the acquisition
of conservation in each future therefore will depend on how that particular future unfolds. 2

The resulting resource portfolio is one that addre sses the risks inherent in the future, not one that has the lowest cost for one specific future. In a given future, portfo lio resources will not necessarily cover their costs in the wholesale electricity market. Some will do very well in certain futures and poorly in others. This is par ticularly true with portf olios that are near the least-risk end of the efficient frontier, where the resources necessary to yield such low risk are so expensive to construct that th ey typically cannot cover their costs in the market. What determines whether a resource portfo lio falls on the efficient frontier at the least-risk end is more determined by whether it reduces total cost in the worst futures. This often comes about by reducing market prices, which usually acts to increase the net cost of resources. Reducing market prices, however, also reduces the risk of expensive market pur chases during times of unexpected need and thereby reduces expected cost.

A traditional resource plan cannot address such scenario risks. Altern ative scenarios can be tested in a traditional sense. This gives an idea of how the ideal plan might change if the future turns out different. However, it will not show how best to prep are when it is not clear which
future will occur.

Because the Council’s power plan di rectly addresses risk, some as pects of its portfolio may look contrary to a traditional approach to resource plans. In traditional planning, new resources are stacked up against growing loads so that new resour ces are scheduled at a particular date to meet requirements. Uncertainty about re quirements is considered by looki ng at different levels of load growth. Uncertainty about hydr opower conditions is addressed by planning for only criticalwater conditions. These are not necessarily the most efficient plans, however, and they are based on how the world works today. These plans typi cally do not consider changing policies that could dramatically affect the cost of different strategies.

The Council’s plan recognizes, howev er, that it may be advantage ous to develop a portfolio for simultaneous construction of different types of re sources. In any given fu ture, only one of these might be constructed. One consequence of this is that, from a traditional load/resource-balance perspective, the option schedule might sugge st the power system would be overbuilt.



### Interpreting Portfolio Costs
Future costs of the power system in the Counc il’s regional portfolio m odel are expressed in traditional planning terms. They are the net presen t value of future power system costs that can

2 Animated graphs that illustrate how selected plans perform under the 750 fu tures are available from the Council’s
website.Chapter 9: Developing a Res ource Strategy Sixth Power Plan

9-9 vary with resource choices made in each future fo r the portfolio. They include the operating cost of existing resources and the capita l and operating costs of future re sources. The capital costs of existing resources are sunk costs and are not affected by future resource choices.

An important distinction exists between the net pr esent-value system costs shown in illustrations of the feasibility space and the optioning cost of a particular portfoli o. The net present-value system costs include costs that are largely outside the control of decision-makers. They include, for example, carbon penalties and natural gas co sts. Option costs ar e the costs for siting, planning, and licensing new generation. They also may include some above-market cost for conservation, depending on one’s view. These costs, the optioning costs, are within the scope of
what decision-makers control.

It is a common misinterpretation of the efficient frontier that th e region is paying for the change in net present-value system costs to achieve th e reduction in system risk represented by the frontier. The average cost and risk, however, are not like the cost and benefit in an economic study. Instead, they represent distinct attributes of th e distribution of outcomes . The decisionmaker can pay the optioning costs of the reso urces, but optioning costs typically are a fraction of
a percent of the average costs illustra ted on the efficient frontier. Depending on the future that actually materializes over the next twenty years, the benefits of optioning resources can, on the other hand, be much larger than the av erage cost along the efficient frontier.

The expected costs in other studies are often m eaningful because they reflect a value to which average costs will trend over time. For exampl e, average hydrogeneration energy and cost are meaningful in utility-production cost studies. The Council’s pri ce forecasts, for example, are based on average hydrogeneration. This use of e xpected energy is meaningful precisely because, over time, the energy and cost will trend to those values, even though they may differ significantly in any given year. Th at is not the case for many of the uncertain variables in this model. In fact, most futures consist of prices and requirements that move progressively away from today’s forecasts. This behavior is importa nt to risk modeling, but it makes expected cost harder to interpret.

The expected costs from the feasibility space di ffer from those in certain economic studies, too, in that typically they include only costs relevant to the selection of a resource portfolio. The fixed costs of the existing system, for example, are not included. Any decisions to modify the existing system of resources, therefore, ca nnot be based only on these costs.

The efficient frontier is a screen for portfolios, based on their relative performance. Their relative performance, in turn, relies only on inde pendent aspects of the po rtfolio’s distribution of possible cost outcomes. These aspects should no t be interpreted like tr aditional economic cost
and benefit.



### Low-Risk Portfolios
The Council looks beyond expected net present- value cost and risk in distinguishing among portfolios. Often, risk originates from short-term events within a future. For example spikes in market electricity prices such as occurred in 2000-2001 can creat e huge cost increases if the region is overly exposed to the market. These short-term even ts are not apparent in net presentvalue costs. The imposition of a high carbon penalty can lead to high-cost futures if the region has become overly reliant on electricity generated at plants that burn coal. The regional portfolioChapter 9: Developing a Res ource Strategy Sixth Power Plan

9-10 model is designed to assess such risks and help the Council build resource strategies that will help avoid the impacts of such events.

The portfolios along the efficient fr ontier are distinguished by cost and risk. At the low-risk end of the efficient frontier, a portfo lio’s behavior in its worst 10 pe rcent of outcomes determines its
selection. It follows therefore th at the benefits of a low-risk portfolio are revealed in those futures. The events that transpire over time within futures determine how risky that future is and
whether our risk metric is correct ly identifying those futures. Prin cipal sources of risk in those futures may suggest alternativ e risk-mitigation mechanisms.

Risk mitigation does not affect all futures equall y. The average cost of the low-risk portfolio will be slightly higher, but it provides protection, similar to an insurance policy, against the most costly future events. Understa nding why particular resources in the low-risk portfolio provide this protection yields insight into their value and into the kinds of futures that would be bad for the region under a given resource portfolio.

Other evidence of reduced risk is reduced rate volatility and re duced exposure to the wholesale power market during high-price excursions. These characteristics of portfolios along the efficient frontier were explored in more detail in the Council’s Fifth Power Plan. 3 A discussion
of the model’s calculation of re venue requirements appears in Ch apter 3 and Appendix O of the
Sixth Power Plan.

In general, portfolios near the lower-risk end of the efficient frontier c ontain more resources and rely less on the wholesale power market. By building more resources and reducing price volatility, these low-risk portfolio s are more consistent with re gulatory preferences and utility planning criteria than the lower-c ost but higher-risk portfolios.



### Interpreting Carbon Emissions and Costs
A new measure of power system performance is the emissions of carbon dioxide from generating plants that burn fossil fuels. It is important because of va rious greenhouse-gas-reduction targets and proposed policies to price carbon emissi ons through a tax or a cap-and-trade system.

Because electricity is generated and transm itted between and among regions of the country, measuring carbon emissions in any one region is difficult. Estimating the emissions from an individual power plant is relativ ely straightforward. But electric ity trading creates a variety of options for counting emissions. One option is to count only the emissions of power plants actually located in the Pa cific Northwest. Another is to count, in addition, the emissions of power plants that are located outside the Paci fic Northwest but whose output is contractually
committed to serve Northwest loads. A third is to count the carbon content of all electricity used to serve Northwest loads. This requires a dding an estimated carbon content of imported power and subtracting the estimated carbon content of exported power from Northwest emissions.

The rules for such accounting have not been es tablished, and proposed ru les often vary by state and region. Such calculations are further complicated by the fact that electric ity that is traded in wholesale markets is not typically identified as coming from a pa rticular plant or technology. For example, what carbon conten t should be attributed to expo rted power? Is power exported

3 Northwest Power and Conservation Council. The Fifth Northwest Electric Power and Conservation Plan. Volume 2, Chapter 7.Chapter 9: Developing a Res ource Strategy Sixth Power Plan

9-11 from the Northwest free of carbon emissions because it is generated by hydroelectric projects, or
does it have substantial carbon emissions because it is generated from the region’s coal plants? Perhaps it should be considered free of car bon, because its price already reflects any carbon penalty paid by producers, directly or through re-dispatching of resources.

Because the accounting treatment is not settled, the Council’s regional portfolio model reports carbon emissions in two different ways. One is ba sed on generation located within, or contracted to, the Pacific Northwest (generation-based). The other is based on the consumption of electricity within th e region (load-based).

For the purpose of calculating load-based car bon, the model assumes imported and exported power has the same amount of carbon -- 1,053 pounds of CO 2 per megawatt-hour of electricity generated. This corresponds to the number pounds of CO 2 per megawatt hour that a natural gasfired combustion turbine would produce if it had a heat rate of 9,000 BTU per kilowatt-hour. This is typical of an older-generation gas-fired po wer plant. It actually is a proxy for the average carbon emissions across all generation in the We stern Electricity Coordinating Council region on the short-run margin over an extended time period, such as a year. Northwest generation averages somewhat lower emissions, and surro unding areas average so mewhat higher during periods when the Pacific Northwest is importi ng power. This amount of emissions does not
reflect the fact that al ternative carbon-cont rol regimes may shift the effective carbon emissions. This assumption does have the advantage, howev er, of being simple and easy to understand. Moreover, it closely resembles the assumed carbon-emissions factor adopted by Washington State Department of Commerce 4 and the California Energy Commission.



## SOURCES OF UNCERTAINTY

Risk resides with a utility’s overall portfolio of re quirements and resources, rather than with one resource, one requirement, or one kind of fuel. Moreover, uncertainty does not necessarily lead
to risk. Thermal-based utilit ies view fuel-price uncertainty and the variation of hydropower generation much differently than do hydropower-bas ed utilities. Modeling the uncertainties that are traditionally the primary sources of risk, however, is the first step in a process to understanding economic risks to the region.



## Wholesale Power Prices

It would be difficult and expensive for an indi vidual utility to exactly match electricity requirements and generation at all times. Therefor e, virtually all utilit ies participate in the wholesale market, directly or indi rectly, as buyers and as sellers. This is particularly so for regional utilities because the region’s primary source of generation, hydroelectricity, is highly
variable from month to m onth and year to year.

Whether a utility has surplus generation or need s to purchase power affects the magnitude and direction of change in costs to electricity consumers when wholesal e power prices rise. That is, if the utility needs power and if electricity market prices go up, consumers’ costs can go up. If

4 See final opinion on California Energy Commission (CEC) Rulemaking 06-04-009, issued September 12, 2008, which calls for a default value of 1,100 pounds per MWh; and Tony Usibelli, Assistant Director, Washington Department of Community, Trade and Economic Development, to the CEC regarding this rulemaking, dated July 10, 2007, which uses 1,014 pounds per MWh.Chapter 9: Developing a Res ource Strategy Sixth Power Plan

9-12 the utility has surplus power to sell into the ma rket, however, and electricity market prices go up, the larger revenues mean the utility’s net elect ricity production costs will come down. This
reduces the revenue the utility needs to collect from the consumers.

Disequilibrium between supply and demand is commonplace for electricity markets. Disequilibrium results from less- than-perfect foresi ght about supply and demand, inactivity due to prior surplus, overreaction to pr ior shortages, and othe r factors. Periods of disequilibrium can last years. The resulting excursions from equilib rium prices can be large relative to the routine variation due to temperatures, fuel prices, plan t outages, and hydro generation. These excursions are a significant source of uncertainty to electr ic power market partic ipants, and they are therefore an important part of the Council’s scenario analysis.

Figure 9-3 shows a sample of electricity price fu tures from among those that the Council’s model uses. Description of the Council’ s electricity price forecast is in Chapter 2 and Appendix D. Typical of commodity price distributions, whic h are bounded below by the price of zero dollars per unit, the distribution in Figure 9-3 is quite skewed.

Figure 9-3: Electricity Price Future

Average prices for wholesale el ectricity over a quarte r are capped at $325 per megawatt in the model. This value corresponds to the $400- per-megawatt-hour FERC price cap imposed over the Western power system. That is, the latter is the maximum hourly price the model would impute based on the former. Electricity prices ra rely hit this level in the Council’s portfolio
model.Chapter 9: Developing a Res ource Strategy Sixth Power Plan

9-13 

## Load Uncertainty

The Council’s model assumes a larger range of va riation in loads than pr esent in the Council’s official load forecast for the sixth plan. The a dditional variation stems in part from seasonal and hourly patterns of load and from weather variation. A much larger source of variation, however, is uncertainty about changing markets for electricity, possible t echnology innovations, and excursions due to business cycles.

Figure 9-4: Load Futures

Figure 9-4 displays a sample of load futures fr om the Council’s model simulations compared to the shaded trend forecast range. A detailed description of the Counc il’s official load forecast and
the treatment of aluminum smelte r loads appears in Chapter 3.



## Fuel Prices

The basis for uncertain natural gas price trends is the Council’s fuel-price forecast range as described in Chapter 2 and Appendix A. In additi on to uncertainty in long-term trends in fuel prices, the modeling representation uses seasonal patterns and brief excursions from these trends. These excursions may last from six months to f our years and then recover back toward the trend path. The duration of the excursion and the dura tion of the price recovery are both functions of the size of the excursion. Figure 9-5 illustrates so me natural gas price futures from the portfolio model simulations (2006$).

As with electricity prices, the price distribution is qu ite skewed. The shaded area corresponds to the high and low ranges disc ussed in Chapter 2.Chapter 9: Developing a Res ource Strategy Sixth Power Plan

9-14 Figure 9-5: Gas Price Futures



## Hydropower Generation

A 70-year history of streamflow s and generation provides the basi s for hydropower generation in the model. The hydropower generation reflects c onstraints associated with the NOAA Fisheries 2008 biological opinion. Moreover, scenarios eval uate resource choices assuming no emergency reliance on the hydropower system, even though such reliance might not violate 2008 biological opinion constraints.

In addition to meeting fish and wildlife requi rements, hydropower opera tion must satisfy other objectives. These objectives in clude standard flood control, river navigation, irrigation, recreational, and refill requirements. A ll scenarios incorporate these constraints.

The modeling assumes no decline of output ove r the 20-year study period due to relicensing losses or other factors that might lead to capabili ty reduction. Nor does it assume any increases due to deployment of removable spillway weirs or turbine upgrades. Ch apter 10 does include, however, a study of the potential effects of removing the four Lower Snake River dams.



## Resource Construction Costs

Recent resource development has rev ealed costs that are significantl y higher than anticipated in earlier planning. The details of expected costs for resource technologies over time appear in Chapter 6. These expected costs, which typi cally trend downward over time, serve as the
benchmark for resource construction cost futures the model uses to capture construction cost uncertainty. The Council’s Generating Resource Advisory Committee assisted the Council in characterizing the types a nd likelihood of futures for construction costs.

The Council’s model uses these futures to assess the likely future economic value of resources, among other things. Economic value is one aspect of the decision the model makes within a
future whether or not to construct a resource.Chapter 9: Developing a Res ource Strategy Sixth Power Plan

9-15 Several cost futures for wind ge neration resources appear in Fi gure 9-6. Each future is a sequence of cost multipliers for “overnight” constr uction. They are applied to a figure of dollars per kilowatt of capacity for a wi nd plant to determine the effec tive overnight construction cost for that plant. The overnight construction cost is the total dollars spent over the plant’s construction cycle, but it does not include any cost s for financing or for delays in construction. Figure 9-6 therefore represents how the overnight cost for constructing a power plant will change
over time. The model takes the cost available at the time of plant construction. The model then effectively places that cost in ratebase and cust omers continue to pay off the construction cost over the life of the plant. Subsequent changes in the multiplier have no effect.

A trend of decreasing real cost from the hi ghs in 2007-2009 is evident in Figure 9-6. This reflects the expected price d ecreases anticipated over the September 2009 – August 2029 period.

Figure 9-6: Construction Cost Futures for Wind Generation

0 0.5

1 1.5

2 2.5Sep-09Sep-10Sep-11Sep-12Sep-13Sep-14Sep-15Sep-16Sep-17Sep-18Sep-19Sep-20Sep-21Sep-22Sep-23Sep-24Sep-25Sep-26Sep-27Sep-28Overnight cost multiplier

Source: workbook "Construction costs 100304.xls", worksheet "Wind Construction Cost/Chart1"

An example of a single construction cost future for severa l generation technologies appears in Figure 9-7. This figure illustrates how construc tion costs generally move together through time, reflecting their shared cost components, such as steel, concrete, and labor. Appendix J provides a more complete description of pr obability ranges of costs over ti me for each resource in Figure
9-7.Chapter 9: Developing a Res ource Strategy Sixth Power Plan

9-16 Figure 9-7: Construction Cost Multipliers

0 1,000 2,000 3,000 4,000 5,000 6,000 7,000Sep-09Sep-10Sep-11Sep-12Sep-13Sep-14Sep-15Sep-16Sep-17Sep-18Sep-19Sep-20Sep-21Sep-22Sep-23Sep-24Sep-25Sep-26Sep-27Sep-28

Solar Thermal Geothermal (Binary Flash) Nuclear

IGCC Coal Wind Class 5

CCCT SCCT Source: workbook "Random Variable 01b.xls", chart "Chart of Futures", future 740



## Climate Change and Carbon Emission Goals

A number of industrialized nations are taking action to limit the production of carbon dioxide and other greenhouse gasses. Within the Unite d States, a number of states, including Washington and Oregon, have initiated efforts to control carbon dioxide production. It appears that the region could see control policy materializing at the fede ral or state level, or through
means such as the Western Clim ate Initiative (WCI) in which Washington, Oregon, and Montana are participants.

It is unlikely that reduction in carbon dioxide production ca n be achieved without cost. Consequently, future climate-contro l policy can be viewed as a cost risk to the power system of uncertain magnitude and timing. A cap and trad e allowance system appears to have been a successful approach to cont rolling sulfur oxides and may be used again for CO 2 production control. Alternatively, a carbon tax has the benefit of simpler administration and perhaps fewer opportunities for manipulation. It is also unclear where in the carbon-production chain – the source, conversion, or use – a control policy would be implemented. It is unclear what share of total carbon production the power-generation sector would bear or what would be done with any revenues generated by a tax or trading system. It is unclear which ratepayer sector will pay for which portion of any costs associated with a control mechanism.

The Council’s scenarios use a fuel carbon-c ontent tax as a proxy for the cost of CO 2 control, whatever the means of implementation. When cons idered as an uncertainty, scenarios represent carbon-control policy as a pe nalty (dollars per ton CO 2 ) associated with burni ng natural gas, oil,
and coal.Chapter 9: Developing a Res ource Strategy Sixth Power Plan

9-17 The model keeps track separately of the two costs that arise from a carbon tax. There is a cost associated with any revenues generated by the ta x. There is also a cost associated with alternative dispatch of resources . Separate accounting facilitates evaluation of the effects of a tax independent of assumptions regard ing the use of the tax revenues.

Each carbon-penalty future is a step up to a ra ndom value, selected by the model, where it remains until the end of the study period (Figure 9- 8 illustrates the penalty in a small handful of futures). The progression of carbon penalty over time is unlikely to resemble any of these futures. Nevertheless, using a large number of futures should provide a fair idea of the risk associated with most paths.

Figure 9-8: Samples on Individual CO 2 Penalty Futures

0 20 40 60 80 10020102011201220132014201520162017201820192020202120222023202420252026202720282029

Years$2006/ton CO2

Source: workbook "Spinner_090710_1402 L811 LR for illustrations.xls", worksheet "CO2_illustration" and Chart1

In the Council’s carbon-risk sc enarios, a carbon penalty can aris e at any time. The modeled probability of such a penalty being enacted at so me time during the forecast period is 95 percent. If a penalty is enacted, its va lue is selected from a uniform distribution between zero and $100 per ton (in 2006 dollars). The resulting proba bility of finding a carbon penalty at or below various levels in each period a ppears in Figure 9-9. The distribu tion indicates an even likelihood of seeing some positive carbon penalty around 2012. This assumption, recommended by the Council’s Generation Resource Advisory Comm ittee and adopted by the Council’s Power Committee, is responsible for the shape of the di stribution. The mean of the distribution over all futures rises gradually to about $47.50/ton of CO 2 by the June – August 2029 quarter. As discussed in Chapter 11, the distribution co rresponds to the range of outcomes that EcoSecurities, Ltd., estimated for the Council.Chapter 9: Developing a Res ource Strategy Sixth Power Plan

9-18 Figure 9-9: Deciles for Carbon Penalty

0 20 40 60 80 100 120Sep-09Sep-10Sep-11Sep-12Sep-13Sep-14Sep-15Sep-16Sep-17Sep-18Sep-19Sep-20Sep-21Sep-22Sep-23Sep-24Sep-25Sep-26Sep-27Sep-28$2006/US ton CO2 100%

90%

80%

70%

60%

50%

40%

30%

20%

10%

0%

mean

Source: workbook "New CO2 Distribution 090425.xls", chart "Carbon Distribution"

Preliminary analyses evaluated alternative carbon-p enalty distributions. Reducing the penalty in each future by half results in substantially the same resource plan for the first decade of the scenario as does the zero to $100 distribution.

There are mechanisms in addition to carbon pe nalties and trading programs to meet carbonemission objectives. Scenarios considered di splacement of existing resources with new renewables or more-efficient gas- fired plants. The Council also evaluated direct curtailment and retirement of existing coal-fired plants. The Council has not ta ken a position in favor of any particular approach to carbon re duction. Rather, the plan provid es information and analysis on alternative approaches. Results of this analysis appear in Chapter 10.



## Plant Availability

Power plants are not perfectly reliable, and forced outages are an important source of uncertainty. The analysis includes simulation of forced outages based on typical forced-outage rates for the generating technologies considered.



## Renewable Energy Production Incentives

The production tax credit and its companion Renewable Energy Production Incentive were originally enacted as part of the 1992 Energy Policy Act. The intent was to commercialize wind and certain biomass technologies. Congress has repeatedly renewed and extended them.

The longer-term fate of these incentives is unc ertain. The original legislation contains a provision for phasing out the credit as the costs of qualifying resources become competitive. Moreover, federal budget constr aints eventually may force re duction or termination of the
incentives.Chapter 9: Developing a Res ource Strategy Sixth Power Plan

9-19 In the model, two events influence the value of the production tax cred it over the 20-year study period. The first event is termination due to co st-competitiveness. The likelihood of termination peaks in about five years in the Council’s m odel. The model provides, however, for the possibility of the credit remaining indefinitely or expiring immediately. The second event that
modifies the credit in the Council’s model is th e advent of a carbon penalty. The value of the credit following introduction of a carbon pena lty depends on the magnitude of the carbon penalty 5

.
The Council did not want any reduction in the va lue of the production tax credit to exceed the advantage afforded renewables by a CO 2 penalty. Such an outcome would be contrary to the likely intent of a CO 2 -control policy. This concern determ ines the value of the production tax credit in the model due to the magnitude of a ny carbon penalty that aris es in a given future.

Production tax credits amounted to $15 per megawatt hour when first adopted and have escalated
with inflation. The current value for wind, closed-loop biomass, and geothermal is $21 per megawatt hour. Investors receive credits only for the first 10 years of pr oject operation. Council modeling scenarios use real, levelized values, however. The levelized value over a 20-year economic life would be about $9.10 in 2006 dollars.



## Renewable Energy Credits

Power from renewable-energy projects currentl y commands a market premium, which can be unbundled from the energy and traded separately as renewable energy credits (RECs). REC value varies by resource and over time, like most commodities. This value reduces the cost of the power source if sold. In th e Council’s model, REC value vari es in a manner similar to other commodities and differs by future.

The Council models the Montana, Oregon, a nd Washington Renewable Portfolio Standards (RPS). The RPS regulations of these states re quire an obligated utility to retain the REC associated with the power produced by the utility ’s renewable resource. That is, the utility cannot buy or build qualifying renewable power and then sell or trade the REC separately. While obligated utilities may sell RECs associated with resource surplus to their requirements, they may also bank the energy to meet future RPS needs. If this makes economic sense, the utility would also not sell the REC.



## OTHER ASSUMPTIONS

This section discusses assumpti ons that are not treated explicitly as uncertainties. These assumptions include those about the treatment of renewable portfolio standard (RPS) resources,

5 If the carbon penalty is below half the initial value of th e PTC, the full value of the PT C remains. If the carbon penalty exceeds the value of the PTC by one-half, the PTC disappears. Between 50 perc ent and 150 percent of the PTC value, the remaining PTC falls dollar for dollar w ith the increase in carbon penalty. The sum of the competitive assistance from PTC and the carbon penalty is co nstant at 150 percent of the initial PTC value over that range. The conversion of carbon penalty ($/US short ton of CO 2 ) to $/MWh is achieved with a conversion ratio 1.28
#CO 2 /kWh. This conversion ratio corresponds to a gas turbine with a heat rate of 9000 BTU/kWh. The Fifth Power Plan, which uses the same approach, has additional explanation and details.Chapter 9: Developing a Res ource Strategy Sixth Power Plan

9-20 conservation, independent power producers, recent resource additions to the existing system, and the treatment of flexibility and capacity requirements.

The plan discusses some assumptions thoroughly in other chapters or in the appendices. Consequently, their description does not appear in this chapter. In particular, Chapter 7
describes the treatment of transmission in Counc il analysis. Resources in the model include the cost of any incremental transmission required and the impact of transmission energy losses. Transmission constraints do not appear explicitly in the model. It is assumed that resources that
do not have additional transmissi on cost can be located such that additional transmission is unnecessary. Finally, the model us es a 5-percent discount rate to equate costs occurring at different times, and this value is derived in Appendix N.



## Existing Renewable Portfo lio Standard Resources

Table 9-1 lists the 1,050 average megawatts of ex isting renewables. Th e table includes about 2,634 megawatts of wind that the region has comple ted or will soon complete. When evaluating the potential for wind generation in the region, th is quantity – which is not included in any specification of new resource capability the m odel may select – must be considered.Chapter 9: Developing a Res ource Strategy Sixth Power Plan

9-21 Table 9-1: Base of RPS Resources

Project Capacity (MW) Service
Year Resource Load CA MT OR WA Biglow Canyon Ph I 125.4 2007 Wind PGE 100% Biglow Canyon Ph II 149.5 2009 Wind PGE 100%

Broadwater 10.0 1989 Hydro NWE 100% Clearwater Hatchery (Dworshak) 2.9 2000 Hydro BPA 22% 78% City of Albany (Vine St) 0.5 2009 Hydro PAC 4% 74% 22%

Coffin Butte 1 - 5 5.2 1995 Biomass Consumers 100%

Combine Hills I 41.0 2003 Wind PAC 4% 74% 22%

Condon 49.8 2002 Wind BPA 22% 78% DeRuyter Dairy 1.2 2007 Biomass PAC 4% 74% 22% Douglas County Forest Products 3.2 2006 Biomass PAC 4% 74% 22% Dry Creek Landfill 3.2 2007 Biomass PAC 4% 74% 22%

Echo 44.6 2009 Wind PAC 4% 74% 22% Farm Power (Rexville) 0.8 2009 Biomass PSE 100% Foote Creek (BPA) 16.8 2000 Wind BPA 22% 78% Foote Creek (EWEB) 8.3 1999 Wind EWEB 100% Foote Creek (PAC) 33.1 1999 Wind PAC 4% 74% 22%

Freres Lumber 10.0 2007 Biomass PAC 4% 74% 22% Georgia-Pacific (Camas) 52.0 1995 Biomass PAC 5% 95% 0% Georgia-Pacific (Wauna) 27.0 1996 Biomass BPA 100% 0%
Goodnoe Hills 94.0 2008 Wind PAC 4% 74% 22% H.W. Hill (Roosevelt Biogas) 1 - 5 10.5 1999 Biomass Klickitat 100% Hampton Lumber 7.2 2007 Biomass Snohomish 49%

Harvest Wind 98.9 2009 Wind Various 20% 80% Hay Canyon 100.8 2008 Wind Snohomish 100% Hopkins Ridge 150.0 2005 Wind PSE 100% Judith Gap 135.0 2006 Wind NWE 100%

Klondike I 24.0 2001 Wind BPA 22% 78%

Klondike II 75.0 2005 Wind PGE 100% Klondike III (BPA) 50.0 2007 Wind BPA 22% 78% Klondike III (EWEB) 25.0 2007 Wind EWEB 100% Klondike III (PSE) 50.0 2007 Wind PSE 100% Leaning Juniper 100.5 2006 Wind PAC 4% 74% 22% Marengo I 140.4 2007 Wind PAC 4% 74% 22% Marengo II 70.2 2008 Wind PAC 4% 74% 22% Martinsdale (Two Dot) 2.8 2004 Wind NWE 100% McNary Dam Fish Attraction 7.0 1997 Hydro N. Wasco 50% Nine Canyon 63.7 2002 Wind COU 100%

Portland Habilitation 0.9 2008 PV PGE 100% ProLogis 1.1 2008 PV PGE 100% Puyallup Energy Recovery Company (PERC) 1 - 3 2.8 1999 Biomass PSE 100%
Qualco 0.5 2008 Biomass Snohomish 100%

Rock River I 50.0 2001 Wind PAC 4% 74% 22% Rough & Ready Lumber 1.2 2007 Biomass PAC 4% 74% 22%

Round Butte 339.0 1964 Hydro PGE 15%

Short Mountain 1 - 4 2.5 1993 Biomass Emerald 100% Sierra Pacific (Aberdeen) 10.0 2003 Biomass Grays Harbor 56% Sierra Pacific (Fredonia) 28.0 2007 Biomass SMUD, SCL 82% 11% South Dry Creek 1.8 1985 Hydro NWE 100%
Stahlbush Island Farms 1.6 2009 Biomass PAC 100% Stateline (AVA) 35.0 2001 Wind AVA 100% Stateline (BPA) 90.0 2001 Wind BPA 22% 78% Stateline (SCL) 175.0 2001 Wind SCL 100%

Tiber-Montana 6.0 2004 Hydro 100%

Tieton 13.6 2006 Hydro EWEB 100%

Two Dot 0.9 2004 Wind NWE 100% Vansycle Wind Energy Project 24.9 1998 Wind PGE 100% Weyerhaeuser (Springfield) 4 (WEYCO) 25.0 1975 Biomass EWEB 100%

Wheat Field 96.6 2009 Wind Snohomish 100% White Creek (Benton PUD) 3.0 2007 Wind Benton PUD 100% White Creek (Cowlitz) 94.0 2007 Wind Cowlitz 100% White Creek (Emerald) 15.0 2007 Wind Emerald 100% White Creek (Franklin) 10.0 2007 Wind Franklin 100% White Creek (Klickitat) 53.0 2007 Wind Klickitat 100% White Creek (Lakeview) 2.0 2007 Wind Lakeview 100% White Creek (Snohomish) 20.0 2007 Wind Snohomish 100% White Creek (Tanner) 4.0 2007 Wind Tanner 100%

Wild Horse Wind 228.6 2006 Wind PSE 100% Wild Horse Expansion 44.0 2009 Wind PSE 100%

Wolverine Creek 64.5 2005 Wind PAC 4% 74% 22%

Source: "Plan 6\Power Plan Documents\Chapter 9 DevStrategy (previously chapter 8)\ Renewables for the RPS.xls "Chapter 9: Developing a Res ource Strategy Sixth Power Plan

9-22 

## Forced-in Renewable Portfolio Standard (RPS) Requirements

Montana, Oregon, and Washington, like many other western states, have legislated goals that obligate utilities to meet a prescribed portion of their energy loads w ith renewable generation according to schedules that extend to 2025, in the case of Oregon. When modeled as an uncertainty related to regional load growth, the Council assumes obligat ed utilities meet 95 percent of their nominal RPS goals. This represen tation captures the possibil ity that utilities will face obstacles to meeting their nominal targets. One mechanism, for example, that might give rise to not meeting targets is the “opt-out” provision. This pr ovision in legislation excuses utilities from meeting their targ ets when meeting the requirements would cause significant rate
increases.

Adoption of RPS legislation by othe r states, in particular Californ ia, is expected to affect the region primarily through the expe cted price of wholesale power. The anticipated change in wholesale electricity prices due to this effect is incorporated in Council modeling, as is the uncertainty around such change.

Renewable resources constructed to meet RPS requirements do not receive a cost reduction due to the sale of renewable energy credits (RECs). When regional utilities acquire renewables to meet their state’s requirements, they must retain any RECs associated with the resource. This has the effect of increasing the cost of the res ource relative to what re newable costs would have been had the utility been able to sell the RECs . Utilities, however, may bank RECs that are not used toward meeting RPS requirements. These cred its may be applied toward future obligations. States differ in the policy regarding how long RECs may be banked and under what conditions.

Modeling does not include wind or geothermal explicitly when an RPS is assumed. Earlier studies suggest that renewables will not be constructed for econo mic reasons earlier than or in greater quantity than required by these standards. In scenarios that assume RPS requirements disappear, wind and geothermal are available for the model to select.

Figure 9-10 provides an example of how existin g RPS resources, banked RECs, and new RPS resources play out for one state under a particular future. This particular example is for the state of Oregon. Obligated utilities’ target portions of energy sales, after c onservation, comprise the heavy, dotted line at the top of the graph. Target s are specified only in a handful of years, so targets for other years are interpolated. Next, it is assumed that obligated utilities achieve only 95 percent of target amounts. The next line down reflects that assump tion. Resources that currently qualify for renewable energy cr edits are illustrate d in dark green.

Based on the current level of RPS development a nd state policy, credit bala nces are calculated. In Oregon, credits do not expire. Renewable energy credit ba lances for Washington and
Montana must be updated every year to account for e xpiring credits, and these two states have different requirements regarding the how soon credits expire. It is assume d that if credits would expire quickly and would not be used, they are sold to offset the cost of the resource.

The light green area corresponds to banked renewabl e energy credits. While RECs do not expire in the case of Oregon, they do get used. RECs are denominated in megawatt-hours. This means that once a REC is used to meet a megawatt-hour of customer energy load in some year, it goes away. Consequently, the light green area ends when energy produced by utility renewableChapter 9: Developing a Res ource Strategy Sixth Power Plan

9-23 resources is insufficient to meet the RPS energy target and Oregon utilitie s have used up their
banked credits.

The energy corresponding to this net requirement, after banked credits are used up, is illustrated in yellow. This energy is assumed to be largel y wind but also geothermal, biomass, small hydro, and photovoltaic solar. Because the ener gy is dominated by wind, wind operating and
construction costs are used for new renewables. These costs are subject to the same construction cost uncertainty as are wind generation resource modeled without RPS requirements. The new resources are also expected to have value deri ved from sale in the wholesale power market,
whereas credits have no associated cost or value of this sort.

Figure 9-10: RPS Source Development

0 200 400 600 800 1000 1200

2006 2011 2016 2021 2026Energy (aMW) Energy credit from new resources

Credit from banked RECs
Net energy from committed resources
Actual/Assumed achievement (aMW)
Annual target (aMW)

Source: workbook "...\Plan 6\Studies\Data Development\Resources\New Resource
Candidates\RPS Resources\Final Plan model\RPS Estimates 6P Final 95% 110909.xls", worksheet "OR

110909"



## Conservation from New Progra ms, Codes, and Standards

Conservation due to existing codes and standards is incorporated in the Council’s load forecast. An example of such a code is the mandated conversion to energy-effi cient lighting throughout the nation beginning in 2012. Such conservation is excluded from programs that the model may select going forward. New conser vation is subject to severe co nstraints on development in the model early in the scenario peri od. Full penetration of lost-oppor tunity conservation is assumed to develop slowly over the next decade.

A large amount of discretionary conservation, howe ver, exists at prices far below the current wholesale power price. Left unconstrained, the model would add as much as 2,000 average megawatts of this conservation immediately. While difficult to quantify, utilities have budget constraints that, given no other consideration, would significantly limit how quickly the region can acquire this conservation. The Council, wi th the guidance of the Conservation Resource Advisory Committee and the Region al Technical Forum, chose a rate of acquisition that itChapter 9: Developing a Res ource Strategy Sixth Power Plan

9-24 considers aggressive but achievabl e: development of discretionary conservation at the rate of 160-average-megawatts-per-year. These constraint s are discussed in Chapter 4 and Appendix E.



## Independent Power Producers’ (IPP) Resources

Independent power producers provide depth to wholesale markets but do not mitigate regional ratepayer costs or risks. IPP plants not currently under contract provide energy for the regional
wholesale market. The IPP owne rs, however, receive the benefits of any energy sold, not the region. There are about 3,335 megawatts of IPP ge nerating capacity currently not under contract to regional utilities. This generation does not have firm transmission access to markets outside the region. The amount that is under contract declines over the next few years. A list of the IPP generation modeled in Council sc enarios appears in Table 9-2.

Table 9-2: Independent Power Producers

Plant name Uncommitted share Project Owner January Capacity

(MW) Big Hanaford CC1A-1E 100% TransAlta 233.4 Centralia 1 85% TransAlta 625.1 Centralia 2 100% TransAlta 625.1 Grays Harbor Energy Facility (Satsop) 100% Invenergy (dba Grays Harbor Energy) 611.7 Hermiston Power Project 100% Calpine, dba Hermiston Power Partners 498.7 Klamath Cogeneration Project 100% Iberdrola Renewables 451.7 Klamath Generation Peakers 1 & 2 100% Iberdrola Renewables 47.5 Klamath Generation Peakers 3 & 4 100% Iberdrola Renewables 47.5 Lancaster (Rathdrum CC) 100% Cogentrix 264.4 Morrow Power 100% Morrow Power (Subsidiary of Montsano Enviro Chem Systems) 23.7

Discounted total 3334.9 Source: workbook "Table of IPPs 100118.xls", worksheet Sheet2



## New Generating Resource Options

Resources explicitly considered include natural gas combined-cycle gas turbines, natural gas simple-cycle gas turbines, wind- power plants, and gasified coal combined-cycle combustion turbines. A complete list appears in Table 9-3, below.

Table 9-3: New Resource Candidates

3⁄4 Conservation

 Discretionary conservation limited to 160 average megawatts per year

 Phased in up to 85-percent penetration maximum 3⁄4 CCCT (415 MW) available 2011-2012 3⁄4 SCCT (85 MW Frame GT) available 2012 3⁄4 Wind generation (100 MW blocks), 4800 MW available by end of study

 No REC credit if RPS are assumed in force

 Costs includes any production tax credit, transmission, and firming and integration costs 3⁄4 Geothermal (14 MW blocks) available 2011, 424 MW (382 MWa) by end of study 3⁄4 Woody biomass (25 MW), available 2014, 830 MW by end of study 3⁄4 Advanced nuclear (1,100 MW), ava ilable 2023, 4,400 MW by end of studyChapter 9: Developing a Res ource Strategy Sixth Power Plan

9-25 3⁄4 Supercritical pulverized coal-fired power plants (400 MW), available 2016 3⁄4 Integrated Gasified Combined-Cycle combustion (518 MW) available 2023, with carbon capture and sequestration 3⁄4 Wind imported from Montana, with new transm ission, available 2011, 1,500 MW by end of study 3⁄4 Five classes of demand response, 2,000 MW ava ilable by end of study, 1,300 MW of this limited to 100 or fewer hours per year of operation

As mentioned in the discussion of existing renewa ble portfolio standard re sources, resources that have a very good chance of completi on are included in the base level of resources. This includes certain other thermal resources having high proba bility of completion. They are not modeled explicitly as new resources.

Table 9-4 shows relatively new resources that are not listed in Table 9-1.

Table 9-4: Recent Construction

project capacity (MW) fuel type in-service
month Arrowrock 1 - 2 15 Hydro Jun 2010 Bettencourt Dry Creek Dairy 2.25 Biomass Sep 2008 Big Sky Dairy 1.42 Biomass 2009
Cassia 29.4 Wind Feb 2009 Danskin (Evander Andrews) CT1 170 Natural gas Jun 2008 Double A Dairy 4.26 Biomass 2009 Flathead County Landfill 1.6 Biomass April 2009 Grays Harbor Energy Facility (Satsop) 650 Natural gas Jul 2008 Mill Creek G enerating Station 150 Natural gas Dec 2010 Mint Farm 319 Natural gas Jan 2008 Mountain Home 42 Wind Sep 2008
Raft River I 15.8 Geothermal Jan 2008

In order to keep the analysis manageable, only new res ources that are found to be costcompetitive and of significant potential 6 , or required by law, are considered in the model. The regional portfolio model evalua tes large numbers of possible portfolios under many scenarios and requires several computers and significant time to devel op a portfolio. The number of generation resources in the model affects the time required for a study. Consequently, small amounts of new micro-hydropower generation, solar thermal, and other smaller sources are assumed to be captured under renewable portfolio standards in the states.



## System Flexibility and Capacity Requirements

Energy balance is central to economic risk and ha s been the focus of C ouncil risk assessment. Regional power crises of the past were associ ated with energy shorta ges and surpluses. Examples include the hydropower generation in sufficiency of the early 1970s and the 2000-2001 West Coast energy crisis. Ov erbuilding thermal power plants in the late 1970s and the unprecedented rate increases and financial failu res that ensued illustrate the dangers of overbuilding.

6 The cutoff for considerati on is around 300 MW of cost-effective potential by 2030.Chapter 9: Developing a Res ource Strategy Sixth Power Plan

9-26 The power system has other requirements, howev er. Power system balance on the sub-hourly level is critical to integration of wind and other variable resour ces. Without providing for system peaking and flexibility requirements, the region risks forgoing resource s that can reduce energy risk. Chronic shortages in the special-pur pose markets for resources that meet these requirements may result, or the power system otherwise may become inefficient.

In modeling wind power, an addition al integration and firming cost is added to that of direct
wind-turbine costs. The model doe s not include any additional reso urces that may be required to provide these services. Current ly, it is unclear how much, or even whether, incremental generation resources may be required for this pu rpose. The action plan of this power plan supports work underway by the regional Wind Integr ation Forum to evaluate those requirements.

The model uses economics to evaluate peaking requirements and contribution. The model can
discern economic value that arises from hourly events, such as forced outages. Economic value determines whether the model will build a power plant. Any value beyond that necessary to cover plant costs lowers the sy stem cost, so the model would choose to add it. Traditional reliability and adequacy assessments of capacity requirements ignore fuel prices or operation costs. It is assumed that if the region needed capacity to meet an unforeseen circumstance, fuel price would not be an issue. If prices were considered, however, very high electricity prices would result. Of significance here is that the model would build mo re resources in this situation specifically to avoid exposu re to these high prices.

Moreover, the Council relies on metrics that the regional adequacy forum has adopted. This forum, a consortium of utilities, regulators, and customers, has produced deterministic energy and capacity load-resource balance standards that incorporate much of what the region has learned about resource adequacy.

The model incorporates the forum’s annual ener gy metric directly in to resource-selection decisions. If a planned resource would not be co nstructed because the m odel forecasts that the resource would not be economic, the model forecas ts the region’s needs according to the forum’s energy balance standard. If the calculation indi cates the region is in danger of resource inadequacy, construction of the least- cost, planned resource continues.

Finally, any plans the model pr oduces that the Council would r ecommend are compared to the forum’s energy and capacity standards. E xperience has shown, however, that economic adequacy produces plans that meet energy ad equacy and peaking requirements. The plan addresses flexibility further in Chapter 12.Sixth Northwest Conservation and Electric Power Plan 

# Chapter 10: Resource Strategy

Key Findings................................................................................................................... ................ 1 A Resource Strategy for the Region ............................................................................................. .. 1 Summary........................................................................................................................ ............. 1 Planning Scenarios............................................................................................................. ......... 2
Scenarios...................................................................................................................... ........... 3 Improved Efficiency ............................................................................................................ ....... 4
Renewable Generation........................................................................................................... ..... 7 Natural Gas-Fired Generation................................................................................................... .. 9 Improving, Expanding, and Preserving the Existing Power System ........................................ 10 Develop Long-Term Resource Alternatives ............................................................................. 11 Value of the resource strategy................................................................................................. ...... 11
Carbon Emissions ............................................................................................................... .......... 20 Response to Risk............................................................................................................... ........ 20 Achieving Carbon-Reduction Targets ...................................................................................... 23 Value of the Hydroelectric System.............................................................................................. . 27



## KEY FINDINGS

The resource strategy for the Sixth Power Plan relies on conservation, re newable generation, and natural gas-fired generation. In addition, the regi on needs to better utilize, expand, and preserve its existing electric infr astructure and research and deve lop technologies for the long-term improvement of the region’s electricity supply. S cenario analysis showed that the electric power sector of the region could meet its share of carbon emission-re duction targets similar to those adopted by some states and propos ed in national legislative in itiatives through three primary actions: achieving the conservation targets in the Council’s plan, meeting existing renewableenergy portfolio standards, and reducing the us e of the existing coal plants by about half.



## A RESOURCE STRATEGY FOR THE REGION

The Council’s resource strategy for the Sixth Po wer Plan provides guidance for Bonneville and the region’s utilities on choices of resources that will supply th e region’s growing electricity needs while reducing the risk associated with uncertain future condi tions. The strategy minimizes the costs and risks of the future pow er system. The timing of specific resource acquisitions is not the essence of the strategy. The timing of resource needs will vary for every utility. The important message of the resource st rategy is the nature of the resources and their priorities.



## Summary

The resource strategy is summarized below in si x elements. The first three are high-priority actions that should be pursued immediately and aggressively. The longer-term actions must be more responsive to changing condi tions in order to provide an a rray of solutions to meet the long-term needs of the regional power system. The last element recognizes the adaptive nature of the power plan and commits th e Council to regular monitoring of the regional power system to identify and adjust to changing conditions.Chapter 10: Resource Stra tegy Sixth Power Plan

10-2 • Efficiency: The region should aggressively develop conservation with a goal of acquiring 1,200 average megawatts by 2014, and 5,900 average megawatts by 2030. Conservation is by far the least-expensive resource available to the region and it avoi ds risks of volatile fuel prices, financial risks associated with la rge-scale resources, and it mitigates the risk of potential carbon pricing policies to address climate-change concerns.

• Renewables: Increasing development of renewable generation is necessary to meet existing renewable portfolio standards. On average, the renewable resources developed
to fulfill state RPS mandates will contribute 1,450 average megawatts of energy, or 4,500 megawatts of installed capacity. Most of the recent renewable development has been wind, and that is assumed to be the primary source of renewable energy in the immediate future. However, power production from wi nd projects creates little dependable peak capacity and increases the need for within-hour balancing re serves. The resource strategy encourages the development of other renewable alternatives that may be available at the local, small-scale level and are cost-effective now. The strategy also encourages research
on and demonstration of different sources of renewable energy for the future.

• Natural Gas: Natural gas-fired generation is likely to be needed to supplement efficiency and renewable resources depending on load grow th and the possible need to displace coal use to meet carbon-reduction goals . Even if the region has ade quate resources, individual utilities or areas may need additional supply for capacity or wind integration. In these instances, the strategy relies on natural gas-fired genera tion to provide energy, capacity, and ancillary services.

• Infrastructure Operation and Investment: Strong emphasis should be placed on improving wind scheduling and system opera ting procedures as cost-effective and achievable initial steps for the purpose of wi nd integration. In addition, the region needs to invest in its transmission gr id to improve market access for utilities and to facilitate development of more diverse co st-effective renewable generation.

• Future Resources: In the long term, the Council en courages the region to expand its resource alternatives. The region should e xplore additional sources of renewable energy, improved regional transmission capability, ne w conservation technologies, new energystorage techniques, carbon capture and sequestration, smart-grid technologies and demand-response resources, and new or adva nced low-carbon gene rating technologies, including advanced nuclear energy. Resear ch, development, and demonstration funding should be prioritized in areas where the Northwest has a comparative advantage or unique opportunities.

• Adapting to Change: The Council will regularly assess the adequacy of the regional power system to guard against power shorta ges, identify departures from planning assumptions that could require adjustments to the plan, and help ensure the successful implementation of the Council’s Columbia River Basin Fish and Wildlife Program.



## Planning Scenarios

The resource strategy is based on analysis of several scenarios. The discussion of the elements of the resource strategy draws on those scenarios so some introduction to the scenarios and theirChapter 10: Resource Stra tegy Sixth Power Plan

10-3 findings is needed. The bullets below summarize ei ght scenarios, or studies, that help determine the resource strategy.



### Scenarios

• Carbon Risk - The carbon-risk scenario is intended to explore what resources result in the lowest expected cost and risk given curr ent policy plus the risk that additional carbon reduction policies will be implemented. It in cludes a range of carbon prices from zero to $100 per ton, which average to $47 per ton by 2030. Specific numbers for average resource development in the resource strategy are taken from this scenario. It is designed to represent the current stat e of uncertainty about future carbon pricing policies and develop a responsive resource strategy.

• Current Policy - The current-policy scenar io includes current policies such as renewable portfolio standards, new plants emissions stan dards, and renewable energy credits, but it does not assume any carbon pricing in the future . It helps identify the effect of carbon pricing risk when added to existing policies.

• No Policy - The no-policy scenario removes current policies from the analysis in addition to assuming no future carbon pricing risk. It does, however, assume that the renewable energy credit market will con tinue to operate. This scenar io permits isolation of the effects of current policy.

• No RPS - This scenario includes future carbon-pr icing risk, but the renewable portfolio standards are removed. Renewable energy cr edits are included. One can compare the
cost-effectives of renewable generation to other responses to carbon emissions pricing risk by comparing this scenario to others.

• $45 Carbon - The $45-carbon price scenario is de signed to achieve the carbon-emission reduction targets in proposed legislation. In stead of uncertain carbon prices from zero to $100, a fixed price of $45 is assumed starting in 2010.

• Coal Retirement - This scenario, like the $45-carbon s cenario, is designed to achieve a particular carbon-emissions reduction target . About half of the existing coal-fired generation in the region is phased out betw een 2012 and 2019. This scenario is done with and without carbon-pricing risk. In th e without-carbon-pricing version, fewer coal plants are retired.

• No Conservation - This scenario assumes that no cons ervation is available to meet future electricity needs or reduce carbon emissions. Carbon pricin g risk is included, as are current policies. This scenario allows estim ation of the role of conservation in reducing
carbon emissions and the effect of conservati on on cost and risk in the face of carbonpricing uncertainty.

• Lower Snake Dam Removal - This scenario explores the cost and carbon impacts that would occur if the four lower Snake River dams were no longer available to meet regional power needs. Car bon pricing risk is included as well as current policies

.

Results of these studies are compared in the di scussion of the elements of the resource strategy, and more detailed comparison of their resu lts appears in the later in the chapter.Chapter 10: Resource Stra tegy Sixth Power Plan

10-4 

## Improved Efficiency

The dominant new resource in the Sixth Power Plan resource strategy is improved efficiency of electricity use, or conservation. The attractiveness of improved effi ciency is due to its relatively low cost and the absence of major sources of risk. Conservation cost s half of alternative generating resources and lacks the risk associated with volatile fu el prices and potential carbon policies. It also has short lead time and is available in small increm ents, both of which reduce risk. Therefore, improved efficiency reduces bo th the cost and risk of the resource strategy.

Energy efficiency has been important in all prev ious Council power plans. The region now has a long history of experience impr oving efficiency. Since the Northwest Power Act passed, the region has developed nearly 4,000 average megawatts. That makes efficiency the fourth-largest source of electricity in the region followi ng hydroelectricity, natural gas, and coal.

The average levelized cost of the efficiency developed in the resource strategy is $36 per megawatt-hour. The comparable estimated co st of a natural gas-fired combined-cycle combustion turbine is $92 per megawatt-hour, and Columbia Basin wind costs $104 per megawatt-hour. Improved efficiency also costs less than the forecast market price of electricity. In the Council’s analysis, extra resources ar e added to provide insurance against future uncertainties. Efficiency improvement provides at tractive insurance for th is purpose because of its low cost. In futures or time periods when the extra resources are not needed, the energy and capacity can be sold in the market and their cost more than recovered.

One result of these characteristics is that in a ll of the scenarios examined by the Council, both in the draft and the final power plan, similar amounts of improved efficiency are found to be costeffective. Its role does not depend significantl y on whether or not carbon policies are enacted. Figure 10-1 shows the amount of efficiency acqui red in various scenarios considered by the Council in the power plan. In al l scenarios except the no-conse rvation scenario, the amount of efficiency averages between 5,500 and 6,000 aver age megawatts. The amount of conservation developed varies in each future considered in the regional portfolio model. For example, in the carbon-risk scenario, while the average conser vation development is 5,900 average megawatts, individual futures can vary from as low as 5,300 average megawatts to as high as 6,600 average megawatts.Chapter 10: Resource Stra tegy Sixth Power Plan

10-5 Figure 10-1: Cost-Effective Conservation Resources

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Developing the amount of efficiency included in the carbon-risk scen ario is estimated to cost the regional power system $15 billion over 20 years 1 . The addition of a comparable amount of gasfired generation would cost $62 billion. The nature of efficiency improvement is that the total
cost is recovered over a smaller number of sale s. Average cost per kilowatt-hour sold will increase, but because total consumption is reduc ed, average consumer electricity bills will be smaller. Consumers who choose not to improve their efficiency of use could see their bills increase. However, if the region does not cap ture the efficiency, th e higher cost of new generating resources will increase everyone’s bills.

The amount of efficiency include d in the Sixth Power Plan is significantly higher than in previous Council plans. For example, in the Fifth Power Plan cost-effective efficiency was 2,500 average megawatts compared to 5,900 megawatts in the sixth plan. To a large extent, this increase is the result of changing technology th at has created new effi ciency opportunities and
reduced costs. The Council ha s identified significant new efficiency opportunities in all consuming sectors. Also important are the increa sed cost of generating alternatives and the risk of increased carbon regulations. Figure 10-2 show s how efficiency improvements are located in various consuming sectors. Additional information on the sources and costs of efficiency improvements is provided in Chapter 4 and Appendix E of this plan.

1 About $6 billion of this amount is alr eady in utility costs as currently expens ed conservation. The additional cost to be recovered is therefore $9 billon over 20 years.Chapter 10: Resource Stra tegy Sixth Power Plan

10-6 Figure 10-2: Cost-Effective Effi ciency Potential by Sector

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Improved efficiency contributes not only to m eeting future energy requirements, but also provides capacity during peak load periods. Th e savings from conservation generally follow the hourly shape of energy use, saving mo re energy when more is being used. As a result, efficiency
contributes more to load reducti on during times of peak usage. Or in other words, efficiency improvements have capacity value, as well as energy value. The Council has built up the shape of efficiency savings from the hourly shape of individual end uses of el ectricity and the costeffective efficiency improvements in those us es. Figure 10-3 shows th e monthly savings of average energy, peak-hour capacity, and mini mum-hour loads in 2030 based on 5,900 average annual megawatts of efficiency. The savings from efficiency actions in the Sixth Power Plan are highest in winter. For example, efficiency improvements that yield average annual savings of 5,900 average megawatts create 8,000 average me gawatts of savings during December. The average capacity savings over the December 18- hour sustained peaking period is about 9,300 megawatts. Savings in the peak hour of December are 10,700 megawatts.Chapter 10: Resource Stra tegy Sixth Power Plan

10-7 Figure 10-3: Monthly Shape of 2030 Efficiency Savings

- 2,000 4,000 6,000 8,000 10,000 12,000

January

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e bruary March A p ril May J une July Aug u st September October Nov e mbe r DecemberAverage Megawatts

Peak Average

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As a comparison, the Council explored the effects of having no efficiency improvements
available. A scenario was run based on the ca rbon-risk scenario but with no new efficiency improvements available. The resulting resource strategy was increased in cost, risk, and carbon emissions. Present value system cost increased 24 percent, from $63.9 billion (2006$) to $87.8 billion. In addition, increased ca rbon taxes would be collected. The tax increase is due to an
increase of carbon emissions from 39.7 million to ns per year to 57 million tons per year. The efficiency gains are replaced by a combination of increased use of existing natural gas and coalfired generation, new gas-fired ge neration, reduced net exports of electricity, and a substantial increase in renewable generation due to increased electricity sales. A nother way of describing the effects of no efficiency improvements on car bon emissions is that even with carbon taxes averaging $47 per ton by 2030 and current rene wable portfolio standards, carbon emissions would not be reduced, on average, from 2005 levels . The efficiency improvements in the sixth plan resource strategy are a ke y to reducing carbon emissions.



## Renewable Generation

Renewable generating resources are an important part of the resource strategy. Wind in particular has been a focus of recent generation development in the Pacific Northwest. Driven by financial incentives and renewabl e portfolio standards in three of the four states, the region has added over 3,400 megawatts of nameplate wi nd capacity since the Council’s Fifth Power Plan. This existing wind is estimated to provide about 1,100 average megawatts of energy generation per year, but only pr ovides about 170 megawatts of dependable peaking capability. Wind resources that have ready access to transmission are competitive with other generation
alternatives.

Renewable resources currently are modeled as wind or geothermal in the regional portfolio model. The Council recognizes that additional small-scale renewable resources are likely available and cost-effective and the plan encourag es their development as an important element of the resource strategy. In a ddition, there are many potential renewable resources that areChapter 10: Resource Stra tegy Sixth Power Plan

10-8 currently either too expensive or unproven techno logies that may, with additional research and demonstration, prove to be valuable future resources.

Renewable generation development in the vari ous scenarios is driven by state renewable portfolio standards. The amount of renewable energy acquired depends on the future demand for electricity because state requirements specify per centages of demand that have to be met with qualifying renewable sources of energy. Across th e 750 futures of demand growth in the carbonrisk scenario, the amount of wind developed on av erage is 1,450 average me gawatts. In terms of available capacity, that is 4,500 megawatts of installed wind capac ity, but only about 225 megawatts of dependable peaking capacity.

Figure 10-4 shows the amount of additional renewabl e energy acquired on average in the various scenarios studied. The figure does not include the 1,100 average megawa tts of existing and committed wind. In scenarios with renewable port folio standards, the average development of additional wind is limited to 1,450 average megawa tts, as required by the standards when the state’s goals are combined. The only exception to this is when no efficiency improvements are assumed. In that scenario, an additional 600 av erage megawatts of wind is developed to satisfy RPS requirements for the highe r electricity sales.

In the two scenarios without rene wable portfolio standards, no po licy and no RPS, the results are different. In the no-policy scenario, only 311 average megawatts of additional renewable generation is developed. In the no-RPS scenar io, which includes the risk of carbon prices between $0 and $100 per ton, 1,008 average megawatts of additional renewable generation is developed; about 70 percent of the amount deve loped in scenarios th at include renewable portfolio standards and carbon pricing risk.

Figure 10-4: Renewable Resource Development

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10-9 

## Natural Gas-Fired Generation

Natural gas is the third major resource in the Sixth Power Plan resource strategy. From anaggregate regional perspective, which is the plan’s focus, the need for additional natural gasfired generation is modest in the carbon-risk scen ario. However, the role of natural gas may be larger than it appears in the Council’s anal ysis for a number of reasons. The regional transmission system has not evolved as rapidl y as the electricity market, resulting in limited access to market power for some utilities. In addi tion, some utilities have lost contract resources and have rapid load growth presenting them with significant near-term re source challenges. New gas-fired generation may be required in such instan ces even if the utilitie s meet their renewable portfolio requirements and develop conserva tion as rapidly as called for in the plan.

There are two types of natural gas-fired genera tion considered in the model: simple-cycle turbines (SCCT) that are most suitable for pr oviding peaking capacity, and combined-cycle turbines (CCCT) that can provide base-load ener gy as well as peaking capacity. The gas-fired plants are optioned (sited and lic ensed) in the model so that th ey are available to develop if
needed in each future. The resource strate gy includes optioning 3,400 megawatts of CCCTs, and 650 megawatts of SCCTs. These options are deve loped in only a relatively small number of futures. The average build-out of natura l-gas fired CCCTs over the 750 futures is 1,000 megawatts. For SCCTs the comparable number is 120 megawatts. In th e carbon-risk scenario, the amount of energy actually generated from ne w CCCTs, when averaged across all 750 futures examined, is 400 average megawatts. For S CCTs the average energy provided is only 20 average megawatts. The contribution of these gas- fired resources would be largest during heavyand peak-load hours, or in poor water years.

While the amounts of efficiency and renewables were fairly consistent across most scenarios examined, the future role of natural gas-fired ge neration is more variable and specific to the scenarios studied. Figure 10-5 shows the av erage amounts of SCCT and CCCT built among the
750 futures considered in each scenario. The actual amount of natural-gas fired generation
constructed varies in each future.

The optioning of CCCTs is largest when there is a need for energy. This occurs, for example, in scenarios that feature energy lost from other resour ces as in the retirement, or decreased use, of existing coal plants or reduced conservation ach ievements. Among these scenarios not only does the amount of gas-fired resources optioned vary, but the likelihood of comp leting the plants also varies. The role of SCCT is gr eater when capacity needs to be re placed. This is prominent in the coal-retirement scenario where capacity from the retired coal plants is lost and in the noconservation scenario where the capacity va lue of new conservation is eliminated.Chapter 10: Resource Stra tegy Sixth Power Plan

10-10 Figure 10-5: Natural Gas-Fired Resource Options

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The particular type of natural gas-fired generation built in the future depends significantly on anticipated future conditions. Specific utility needs drive resource choices. For example, individual utilities may find their circumstances include need for within-hour balancing reserves, a system with differing capacity requirements, or limited access to market resources. All of these factors limit the ability of the regional resource strategy to be specific about optioning and construction dates for natural gas fired resources, or for the types of natu ral gas-fired generation.

Nevertheless, it is clear that after efficiency a nd renewables, natural gas- fired generation is the most cost-effective resource option for the region in the near-term. Other resource alternatives may become available over time , and the Sixth Power Plan reco mmends actions to encourage expansion of the diversity of resources available.



## Improving, Expanding, and Preser ving the Existing Power System

The existing Northwest power system is a signifi cant asset for the region. The FCRPS (Federal Columbia River Power System) provides lo w-cost and carbon-free energy, capacity, and flexibility. The network of transmission constr ucted by Bonneville and th e region’s utilities has supported an integrated regional power system. Howe ver, this regional infrastructure is in need of protection and expansion. In addition, the oper ation of the regional power system needs to
evolve to better facilitate an e fficient electricity market and he lp provide improved capacity and flexibility.

A key part of the Council’s resour ce strategy is to improve the ope ration of the power system to better integrate variable wind generation and support growin g capacity requirements. Improved wind forecasting, within-hour scheduling of reso urces, and increased us e of dynamic scheduling among balancing authorities are likely to provide cost-effective and near-term solutions toChapter 10: Resource Stra tegy Sixth Power Plan

10-11 capacity and flexibility needs. The region has r ecently made significant progress through a joint initiative of Columbia Grid, Northern Tier Transmission Gr oup, and WestConnect.

For many years the region has failed to make significant investments in its transmission infrastructure. As a result, transmission cons traints have become significant, limiting access to regional electricity resources and reducing the efficiency of the power system. Recently, transmission investments have gained attenti on and important investments have been proposed or are underway. One area where added transmis sion may have value is in improving access to
more diverse and cost-effective wind and other renewable resources. In vesting in the regional transmission system is important to preserving an efficient and low-cost power system for the region.

Finally, preserving the capability of the existing hydroelectric system has significant value for the region. Mitigating damage to anadromous fi sh from development of the FCRPS has changed the operation of the hydroelectric system, reducing its energy capability and its flexibility. It is important to mitigate this damage, but also to do it in a way that best preserves the value of a
low-cost and low-carbon electricit y source. The Council attempts to ensure that its fish and wildlife program uses cost-effective strategies to improve salmon and steelhead survival. An analysis of the effects of a lo ss of hydropower capability was done to illustrate the value of the system. The example analyzed was the loss of th e four lower Snake River dams. This example is provided to illustrate the significant economic and carbon-emission changes that resulted from the scenario. The last section of this chapte r describes the results of this analysis.



## Develop Long-Term Resource Alternatives

The fifth element of the Council’s resource stra tegy recognizes that technologies will evolve significantly over the 20 years of the Sixth Power Plan. When the Council next develops a power plan, the cost-effective, available and re liable resources will be different from those
considered in the Sixth Power Plan. But the Sixt h Power Plan indentifies areas where progress is likely to be valuable and includes actions to explore and develop such resources and technologies. In many instances the region can influence the development of technology and the pace of adoption.

Areas of focus in the long-term resource strate gy include additional effi ciency opportunities and the ability to acquire them, energy-storage tech nologies to provide cap acity and flexibility, development of smart-grid technologies, expans ion of demand response capability, and tracking the status and cost of poten tial no-carbon or low-carbon gene ration. The latter potentially includes renewable technologi es, carbon sequestration, and a dvanced nuclear generation.

Research, development, and demonstration of thes e technologies is an important part of the Council’s resource strategy. Track ing these developments, as well as plan implementation and changing assumptions, will indentify needed change s in the power plan and near-term actions to implement it. These elements of the resource st rategy are addressed primarily in the action plan.



## VALUE OF THE RESOURCE STRATEGY

The resource strategy of the Sixth Power Plan is designed to provide a low- cost electricity supply to meet future load growth. But it is also designe d to provide a low-risk electricity future for theChapter 10: Resource Stra tegy Sixth Power Plan

10-12 region. The Council choose to make risk reduction an important part of the resource strategy. Therefore the amount and type of resources included in the strate gy are designed to meet loads, reduce costs, and help reduce the risks posed by uncertain future events.

All of the scenarios evaluated for the plan incl ude the same uncertainty regarding fuel prices, hydropower conditions, electricity ma rket prices, capital costs, and load growth. In addition,
several scenarios include the ri sk of carbon pricing. The zero-to -$100-per-ton carbon price risk is included in the carbon-risk, no-RPS, coal-ret irement with CO2 pricing, no-conservation, and Snake River Dam scenarios. Carbon prices are not included in the no-po licy or current-policy scenarios, nor are they included in the coal-retirement scenario without carbon price risk. The $45-carbon scenario assumes a fixed carbon price, instead of uncertain carbon prices. By comparing the results of these various scenarios, the effect of this significant uncertain future carbon-pricing policy on the resour ce strategy can be illustrated.

Figure 10-6 shows the resource development by res ource type for each scenario. The resources are shown as average resource additions over 750 fu ture scenarios. The high and consistent role of efficiency stands out. This is because of both its low cost and its role in mitigating risk from fuel price uncertainty and volat ility. Efficiency acquisition is higher in scenarios with carbon prices reflecting its additional value for mitig ating carbon price risk. Without conservation, renewable and gas-fired genera tion development is much greater. In the no-conservation scenario the net present value of future power system costs increases by $24 billion, or 37 percent even without consideri ng the additional carbon penalties that would have to be paid
because carbon emissions increase from 40 million tons to 57 million tons per year. Without efficiency improvements, regional power costs would also increase by 37 percent excluding the cost of carbon and 47 percent including the cost of carbon

The role of renewable generation is driven by renewable portfolio standards and renewable energy credits. In the absence of both, little addition renewable development would take place. Assuming renewable energy credits continue, but without renewa ble portfolio standards, the amount of renewable generation developed is about 70 percent of what is required by the standards, even in the face of carbon price risk. The higher renewable generation in the noconservation scenario reflects hi gher electricity consumption, wh ich increases the amount of renewable energy needed to meet the standards.

The role of natural gas varies among the scenarios. It is grea test by far in the absence of efficiency. In scenarios with carbon prices or co al retirement it is simila r because it is providing energy to reduce the use of coal. Because the co al-retirement and carbon-pricing scenarios have been designed to reduce carbon emissions to sim ilar targets, the need for coal replacement is
about the same in these scenarios. In the coal-retirement scenario without carbon pricing, simple-cycle combustion turbines pl ay a larger role to replace the capacity of retired coal plants. If the plants aren’t retired they continue to provide capacity under some future conditions.Chapter 10: Resource Stra tegy Sixth Power Plan

10-13 Figure 10-6: Average Resource Developmen t by Type in Alternative Studies

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One of the key issues identified for the Sixth Power Plan was climate-change policy and the potential effects of proposed carbon-pricing po licies. In addition, the Council was asked to address what changes would need to be made to the power system to reach a specific carbon reduction goal and what those changes would co st. The next section focuses on meeting carbonreduction targets, but some more general car bon-emission results are addressed here. In providing analysis of carbon em issions and specific pricing or carbon-reduction targets, the Council is not taking a position on future climat e-change policy. The Council’s analysis is intended to provide useful information to policy-makers.

Figure 10-7 shows the costs and carbon emissions from all of the scenarios in the plan. The role of renewable portfolio standards in providing carbon reductions is one issue. This can be addressed by comparing results between two pairs of scenarios. The primary difference between the no-policy scenario and the curr ent-policy scenario is renewable portfolio standards. In this comparison renewable portfolio standards reduce carbon emissions by 4 million tons per year, from 60.3 to 56.3 million tons per year. Conservati on in the no-policy scenario slows the growth of carbon emissions, but emissions still increase above 2005 levels. The addition of renewable standards in the current-policy scenario redu ces carbon emissions to 2005 levels by 2030. The
renewable standards were estimated to increase the average cost of the power system by about 8 percent while reducing carbon emissions by about the same percentage.

The second comparison that shows the potential effects of renewable portfolio standards on carbon emission is the no-RPS scenario compared to the carbon-risk scenario. In these scenarios, which both include carbon-pricing ri sk, the presence of the standards reduced carbon emissions by 0.6 million tons per year, from 40.3 to 39.7 million tons per year. These results do not include, of course, the value of renewable portfolio standards in encouraging development of new carbon-free technologies for the future as encouraged in the Counc il’s resource strategy.

The effects of carbon pricing risk on emissions can be seen by comparing the carbon-risk scenario to the current-policy scen ario. The carbon-risk scenario a dds to the expected cost of theChapter 10: Resource Stra tegy Sixth Power Plan

10-14 power system and reduces carbon emissions compared to the current-policy scenario. Expected power system cost increases about 14 pe rcent, from $56.1 billion (2006$) to $63.9 billion. Average carbon emissions decrease by 29 percent in 2030 reaching levels about 30 percent lower than 2005. By comparing emission levels and cost between the carbon-risk and the noconservation scenarios, it becomes clear how impo rtant efficiency improvement is for reducing
carbon at the least cost. Carbon emissions ar e not reduced from 2005 levels in the noconservation scenario, but power system cost incr eases by $24 billion, or 30 percent. If the carbon penalty is included in cost, the increase is ev en larger.

Figure 10-7: Costs and Carbon Emissions by Scenario in 2030

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Emissions

Figure 10-7 shows costs as the net present value of system costs, which is the measure of cost used for planning. It includes only the forward-going costs of th e power system; that is, costs that can be affected by future c onditions and resource decisions. Some have noted that reporting costs as net present values does not show pa tterns over time and obscures differences among
individual utilities. The latte r is unavoidable in regional pl anning and the Council has noted throughout the plan that diffe rent utilities will be a ffected differently by altern ative policies. It is possible, however, to display the temporal patter ns of costs among scenarios. Figure 10-8 shows forward-going power system costs for selected scenarios on an annual basis. Forward-going costs include only the futu re operating costs of existing reso urces and the capital and operating costs of new resources. The 2010 value in Figu re 10-8 therefore include s mainly operating costs of the current power system, but not the s unk capital costs of the existing generation, transmission, and distribution system.Chapter 10: Resource Stra tegy Sixth Power Plan

10-15 Figure 10-8: Annual Forward-Going Power System Costs

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Power system costs increase over the forecast peri od even in the no-policy scenario. Renewable portfolio standards increase co st slightly in the current-pol icy scenario. The carbon-risk scenario, which best represents the resource st rategy of the Sixth Power Plan, increases costs significantly, but not having conser vation available in the future increases costs dramatically. The costs in Figure 10-8 all incl ude the CO2 penalty that woul d occur on average if carbon pricing were implemented, but th ree of the scenarios include no carbon-pricing policy: no policy, current policy, and coal retireme nt without carbon pricing. If carbon penalties were excluded from these costs, the cost of the carbon-risk a nd no-conservation scenarios would appear lower. The other scenarios analyzed in the plan all would appear about the same as the carbon-risk scenario if included in Figure 10-8.

To translate these planning costs to the change s that would likely be experienced by consumers in their rates and bills, existing power system co sts need to be included and some costs that are not recovered through utility elect ric revenues need to be excluded. Figure 10-9 shows an index of forecast total utility revenue requirements fo r the carbon-risk scenario in the context of historical levels. The higher line of forecasts includes average carbon penalties as if they were entirely recovered thr ough electricity revenues. Below, these revenue requirements are translated into electric rates and typical reside ntial customer monthly el ectricity bills. The addition of existing system costs makes these im pacts on consumers appear smaller than looking only at forward-going costs. The rate and bill effects are further dampened by the fact that conservation costs are not all recovered through u tility rates. In fact, it becomes difficult to graphically distinguish among the ef fects some of the scenarios.

If the Council had developed a resource strate gy based on current policies only, it would be lower cost as long as carbon pric ing were not implemented in the future. It would be a strategy with fewer new resources and slightly lower rates and bills. However, if that resource strategy
was followed and the future turned out to have significant carbon-pricing policy, costs could turn out to be substantially higher. Existing coal plants would have to be used to meet load and the carbon costs required by their emissions would be s ubstantial. The extra cost of the resource strategy that considers carbon-pric ing risk helps insure the region against future situations that could be expensive.Chapter 10: Resource Stra tegy Sixth Power Plan

10-16 Figure 10-9: Index of Historical and Forecast Utility Revenue Requirements

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With CO2 Costs

Without CO2 Costs 1990-2008 Historic Values

The effects of the different scenarios on costs ar e translated into possible effects on electricity rates and residential consumer monthly electricity bills. The rate estimates are average revenue requirements per megawatt-hour. The residentia l bills are typical monthly bills. Both are expressed in constant 2006 dollars and have been levelized over the forecasting period. As can be seen in Figure 10-10, levelized rates and bills generally move in the same direction as the net present value of system cost that is reported as power system cost in this plan. The only exception to this relationship is in the no-conser vation scenario. There, bills increase with system cost without conservation, but rates de crease because costs are spread over a larger number of megawatt-hours sold without conservation. Figure 10- 11 illustrates how efficiency improvements lower electricity bills.Chapter 10: Resource Stra tegy Sixth Power Plan

10-17 Figure 10-10: System Costs, Rates, and Monthly Bills

0.0 10.0 20.0 30.0 40.0 50.0 60.0 70.0 80.0 90.0 100.0

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icy No Policy No RP S $45 C O2 Cost Coal Retire me

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Figure 10-11: Residential Electricity Bills With and Without Conservation

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2 0 10 2012 20 1 4 2 0 1 6 2 0 18 2020 20 2 2 2 0 2 4 2026 2028Monthly Residential Bills (2006$)

Carbon Risk

No Conservation

The changes in rates and bills are small relative to system-cost changes. The primary reason is that revenue requirements contain a substantia l amount of existing costs that do not change among the scenarios. The system costs used in planning exclude existi ng, or sunk costs and instead include only forward-going costs that could be affected by resource decisions. The
effects of carbon reduction on rates and bills are smaller than some participants in the Council’s planning process expected. One reason is that conservation addresses much of the problem and it is cheap. A second reason is th at the region is fortunate to ha ve a low-carbon power system. Most of the carbon emissions come from a relatively small share of the generation that is fired by coal. This makes achieving substantial carbon reductions less costly than in many regions.Chapter 10: Resource Stra tegy Sixth Power Plan

10-18 Figure 10-12 shows monthly resi dential bills in the current- policy, carbon-risk, and coalretirement scenarios. Figure 10- 13 shows electricity rates for the same scenarios. Neither figure includes carbon penalties in rates or bills. The coal-retirement scenario does not include carbon pricing policy, nor does the current-policy scenari o. Therefore, the bills and rates of those scenarios do not change if car bon costs are included. The eff ects of including carbon costs in
bills and rates are illustrated in Figures 10-12a and 10-13a, resp ectively. Including carbon cost in revenue requirements raises the bills and rates of the three scenarios th at include carbon risk. If the carbon penalty is counted as a net cost to consumers, th e carbon-risk scenario results in higher bills than the coal-retirement scenario. Co al retirement results in the highest rates if carbon costs are excluded, but when carbon costs ar e included rates in th e carbon-risk and noconservation scenarios are higher than in the coal-retirement scenario.

Figure 10-12: Monthly Residential Bills Ex cluding the Cost of Carbon Penalties

Average Bills w/o CO2 Tax

0.00 20.00 40.00 60.00 80.00 100.00 120.00

2 0 10 2011 2 0 1 2 2013 20 1 4 2015 2016 2017 2018 2019 2020 2021 2022 2 0 23 2024 2 0 25 2026 2 0 2 7 2028 20 2 92006$ Per Month Per Household

Carbon Risk Current Policy No Policy

Coal Retirement w/o CO2

No ConservationChapter 10: Resource Stra tegy Sixth Power Plan

10-19 Figure 10-12a: Monthly Residential Bills In cluding the Cost of Carbon Penalties

Average Bills w/ CO2 Tax

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20

10 2011 20 12 20 13 2 0 14 2015 20 16 20 17 2018 20 19 20 20 2 0 21 2022 20 23 20 24 2025 20 26 20 27 2 0 28 20292006$ Per Month Per Household

Carbon Risk
Current Policy No Policy

Coal Retirement w/o CO2

No Conservation

Figure 10-13: Electricity Rates Excludi ng the Cost of Carbon Penalties

Average Rates w/o CO2 Tax

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No Policy

Carbon Risk
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No Conservation

Coal Retirement w/o CO2Chapter 10: Resource Stra tegy Sixth Power Plan

10-20 Figure 10-13a: Electricity Rates Incl uding the Cost of Carbon Penalties

Average Rates w/ CO2 Tax

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0 2 0 20 2 1 2

0 22 2 0 23 2 0 2 4 20 2 5 2

0 26 2 0 27 2 0 2 8 20 2 92006$ Per Megawatt-Hour

Carbon Risk Current Policy No Policy

Coal Retirement w/o CO2

No Conservation

The pattern of change of rates and bills in other scenarios doe s not vary greatly from those shown in Figures 10-12 and 10-13. Th e trends in rates show a gra dual increase, while the trends in bills show a gradual decrease. The one scenario that does have a significant effect on bills is
the no-conservation scenario. Without the conser vation available, the region, faced with carbonprice risk, would experience signific antly higher electricity bills. This is apparent in Figures 10- 11 and 10-12 compared to the carbon-risk Scenario. The no-conservation scenario results in about $5 per megawatt-hour lower rates until near the end of the planning period when the two
scenarios’ rates conve rge (see Figure 10-13).



## CARBON EMISSIONS

Response to Risk

One of the most important issues identified for th is power plan is climate change and the possible effects that policies to reduce carbon emissions might have on the Northwest’s power system. Current policies include renewabl e portfolio standards in three of the four Northwest states, limits on carbon emissions from new power plants, announced carbon-reduction goals, and numerous initiatives to reduce greenhouse-gas emissions from energy use. Additional policy discussions at the state, regi onal, and national levels have focused on some form of carbon pricing with most proposals focusing on a cap-and-trade system for carbon.

The uncertainty of future policies has been tr eated as one of the ke y risks facing the power system in the regional portfolio model. The ca rbon-risk scenario assumes that some form of price could be placed on carbon em issions, but the timing and level of the price are treated as
uncertain. The intent of this scenario is to examine what actions shoul d be taken by the power system in the face of likely but uncertain carbon -control policy. In this scenario, carbon pricing
can be enacted at different times in the future , and when it is, the prices can be anywhere between $0 and $100 per ton of carbon dioxide emi ssions. One of the problems of unresolved policy direction is that utilities and business ca nnot anticipate what actions are going to beChapter 10: Resource Stra tegy Sixth Power Plan

10-21 required. Any decisions made toda y may turn out to be costly when policy is enacted some time in the future. This uncertainty can result in delayed decisions about additional resource
investments. The carbon-risk scenario provides some guidan ce for current decisions, when
future conditions are unknown.

The results of the carbon-risk scenario can be co mpared to a current-polic y scenario that assumes current policies will continue into the future; th at is, it includes no risk of carbon-pricing policy in the future. A comparison of these two scenar ios is shown in Table 10-1. Analysis of the
carbon-risk scenario indicates that the most cost-e ffective response to carbon- pricing risk is more efficiency and more natural gas-fired generation. The actual natural gas-fired generation built is much lower than the option amounts shown in Ta ble 10-1, but the increased natural gas options indicates the strategy that makes sense in the f ace of significant carbon-pricing risk. The role of the increased natural gas-fired generation is to provide energy replacement for existing coal plants that would be used less wh en high carbon taxes are encountered.

Table 10-1: The Carbon-Risk Scenario versus the Current-Policy Scenario Current Policy Carbon Risk Cost (billion 2006$ NPV) With Carbon Penalty Without Carbon Penalty $56.10 $56.10 $123.5 $63.9 Change in Retail Rates from Current Policy (levelized 2006$) Including Carbon Penalty Without Carbon Penalty + 8.6% + 1.4% Carbon Emissions (Gen) (Million Tons/Year in 2030) 56.3 39.7

Resources 2030 Conservation (MWa) 5,572 5,895 Renewables (MWa) 1,480 1,453 CCCT Options 2030 (MWa) 1,512 3,402 SCCT Options 2030 (MWa) 1,620 648

Current (2005) carbon emissions from the Nort hwest power system are estimated to be 57 million tons per year (MMtpy) when adju sted to normal hydropower conditions. The comparable number for 1990 is estimated at 44 MMtpy. These are important numbers because proposed carbon-reduction targets usually are stated in terms of future em issions levels relative
to either 2005 or 1990 levels. Based on simula tions of the regional portfolio model , carbon emissions in the current-policy scenario are he ld fairly constant at 2005 levels through 2030. The commitment to aggressive efficiency impr ovement is largely responsible for limiting the growth of carbon emissions from the power system in the current-policy scenario. Actions taken
in the carbon-risk scenario reduce carbon em issions by 30 percent from 2005 levels and by 10 percent from 1990 levels. The ca rbon reductions targeted by mo st stated or implied policy
initiatives for 2020 are met in the carbon-risk scenario. 2 Continued reductions in carbon emissions would be required to meet long-term carbon reduction targets. Interpolation from 2020 targets to 2050 targets would place 2030 em issions targets between 35 and 40 MMtpy assuming the power sector is required to achieve carbon reductions in pro portion to its share of
total emissions.

2 See description of policies in Chapter 11.Chapter 10: Resource Stra tegy Sixth Power Plan

10-22 Figure 10-14 shows the average annual carbon emi ssions for the carbon-risk scenario compared to the current-policy scenario a nd another scenario that includ es carbon price risk but does not
include conservation as a resource (the no-conservation scenario). The figure illustrates the importance of the two key actions that will be required to meet car bon reduction goals: reduced coal use and increased efficiency.

Figure 10-14: Average Annual Carbon Emis sions for Current-Policy, Carbon-Risk,
and No-Conservation Scenarios

0.0 10.0 20.0 30.0 40.0 50.0 60.0 70.0

2010 2011 2012 201

3

2014 2015 2016 201

7

2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029Million Tons Per Year (Resource)

Carbon Risk

No Conservation Current Policy

It is important to recognize, however, that th e average carbon emissions shown in Figure 10-14 hide a great variety of possi ble future carbon emissions over the 750 futures simulated by the regional portfolio model. To illustrate this, Figure 10-15 shows the frequency distribution of
2030 carbon emissions for all 750 futures. Across the simulated futures, which vary in loads, carbon prices, natural gas prices, electricity market prices, and other conditions, carbon emissions range from less than 10 MMtpy to over 80 MMtpy. This se nsitivity of carbon emissions to hydroelectric and othe r conditions makes verification of emissions levels difficult. Further, there are many different approaches to measuring and counting a region’s carbon
emissions. The measure that is shown in this plan is based on generation within, or committed on a long-term basis to, the region. An alternat ive approach is to base the carbon-emissions estimate on electricity consumpti on within the region. The Council calculates this concept as well, and because in most of the scenarios examined the Northwest is a net exporter of electricity, this measure of regional carbon emissions is lower. Because of all these factors, it would be inappropriate to make any definitive conclusions regarding carbon-emissions reduction targets and whether emission targets are achieved.Chapter 10: Resource Stra tegy Sixth Power Plan

10-23 Figure 10-15: Frequency Distribution of Carbon Emissions in the Carbon-Risk Scenario

0 20 40 60 80 100 120 140 160

0-10 11-20 21-30 31-40 41-50 51-60 61-70 71-80 81-90 91-100

Bins of Carbon Emissions in M illion Tons Per Year Target

Reducing carbon emissions in the carbon-risk scen ario is not free. Th e expected net present value of power system costs increases by $7.8 billi on, or 14 percent, if only changes in the cost of electricity generation are included. The cost is $22.8 bill ion, or 40 percent greater, if the carbon price itself is included. The carbon price, perhaps a carbon tax, for example, may or may not be a net cost to the region depending on how th e revenues from the tax are treated. Even for utilities the tax burden may be mitigated by other ch anges in taxation or credits. The structure of carbon-pricing policy is unknown at this time so both cost extremes are included in the plan.



## Achieving Carbon-Reduction Targets

The carbon-risk scenario develops a resource strategy that addresses risk of future carbon costs. Another approach suggested in comments on the dr aft power plan is to de sign scenarios that are intended to achieve particular carbon-emissi on targets. As discussed above, 2030 carbon emissions targets fall into the 35-to-40-MMtpy range. Two scenarios examined alternative
means to achieve carbon emissions levels that meet this target on average over the 750 futures simulated in the regional portfolio model.

The first scenario seeks a fixed carbon-emissi ons penalty that achieves the carbon-emissions target. Because the lowest pena lty that achieves the target is $45 per ton, it is called the $45-
carbon scenario. The tax is assume d to be implemented immediately in 2010. The level of this tax is similar to the average carbon tax in 2030 for the carbon-risk scenario, which assumed uncertain carbon taxes that, on average, increase over time.

Because it is clear that any si gnificant carbon reduction requires reduced use of existing regional coal plants, the second scenario examined the retirement of enough coal-fired generation to meet the average emissions target. This is labeled the coal-retirement scenario. In the coal-retirement scenario, approximately half ( 54 percent or 2,700 average megawa tts after planned and forced outages) of the region’s coal-fired generati on capability is phased out between 2012 and 2019.
Because coal retirement is viewed as an alternativ e to carbon pricing in this scenario, there is noChapter 10: Resource Stra tegy Sixth Power Plan

10-24 carbon penalty in this study. An analysis of coal retirement with carbon pricing uncertainty has
also been done and is discussed below.

Both of these scenarios meet the carbon emi ssions target of between 35 and 40 MMtpy by 2030,
as did the carbon-risk scenario. However, the levels of carbon em issions, costs, and certainty of carbon reductions vary among them. Table 10-2 compar es the results of the three scenarios. If the carbon penalties themselves are not included, the present va lue system costs of the three scenarios are very similar. If the carbon pena lties are included (fir st row of Table 10-2) scenarios with carbon pricing are more costly. Because the carbon risk scenario includes many futures with prices well above the $45-per-ton-level, its cost is ev en higher than the $45 scenario.

Table 10-2: The Carbon-Risk S cenario versus Current Policy
Carbon Risk $45 Carbon Coal Retirement Cost (billion 2006$ NPV) With Carbon Penalty Without Carbon Penalty $123.5 $63.9 $85.7 $64.2 $64.3 $64.3 Change in Retail Rates from Current Policy (levelized 2006$) Including Carbon Penalty Without Carbon Penalty + 8.6% + 1.4% + 12.9% + 2.9% + 2.9% + 2.9% Carbon Emissions (Gen) (Million Tons/Year) 39.7 37.0 36.3

Resources 2030 Conservation (MWa) 5,895 5,933 5,825 Renewables (MWa) 1,453 1,450 1,459 CCCT Options 2030 (MWa) 3,402 1,890 3,024 SCCT Options 2030 (MWa) 648 1,620 3,240

The role of conservation and the amount of rene wables needed to meet renewable portfolio standards are very similar among the scenarios. The amount of natural gas-fired generation, however, does change. The role of natural ga s-fired generation depends on how much energy and capacity needs to be replaced and how much risk needs to be insured against. In the $45- carbon scenario, the cost of carbon is known as is th e viability of existing co al plants. There is still variability based on uncertain natural gas prices, but on averag e less coal energy needs to be replaced than in the coal-retirement or carbon-r isk scenarios. The coal-retirement scenario requires more natural gas-fired generation than th e $45-carbon scenario to replace the energy and capacity of retired coal plants. The carbon-ri sk scenario requires more natural gas-fired generation than the $45-carbon scenar io because of the risk of higher carbon penalties and the reduced cost-effective coal and inefficient gas-fired generation that ensues.

These three scenarios vary in their certainty of ca rbon reduction across the 750 futures that the regional portfolio model examines. Figure 10- 16 shows a frequency distribution of carbon emissions, similar to Figure 10-15, for each of th e three scenarios that, on average, meet the carbon-emissions target compared to the curren t-policy scenario. The carbon-risk frequency
distribution is the same as show n in Figure 10-15. All of the three carbon scenarios shift the
distribution of carbon emissions to the left. The distribution of the $45-carbon and carbon-risk scenarios are generally similar to one another. The coal-retirement scenario, however, focuses the emissions much more into the 20- to 40-MMtpy area.Chapter 10: Resource Stra tegy Sixth Power Plan

10-25 Figure 10-16: Carbon Emissions Freque ncy Distribution in Four Scenarios

0 50 100 150 200 250 300 350

0-10 11-20 21-30 31-40 41-50 51-60 61-70 71-80 81-90 91-100

Bins of Carbon Emissions MMtpy Carbon Risk
Coal Retire $45 Carbon Price Current Policy Target

Another way to summarize the differences among the carbon scenarios and the current-policy scenario is to calculate the probability that e ach scenario will result in carbon emissions below 40 MMtpy. Figure 10-17 shows these probabilities. With current policies, the likelihood of emissions falling below 40 MMtpy in 2030 is only 23 percent. Coal reti rement is the most certain of the policies to achieve the target under the variety of future conditions examined by the model. It achieves less than 40 MMtpy in 79 per cent of the 750 futures. Pursuing actions to mitigate the risk of uncertain ca rbon pricing, as in the carbon-risk scenario, will achieve success in 61 percent of the futures, while a fixed carbon tax of $45 would achieve success in about 66 percent of the futures. Figure 10-17 includes the coal-retirement scenario combined with carbon pricing (coal retirement w/ CO2). In this sc enario carbon prices do most of the carbon-reduction work. Only about 13 percent of the existing coal-fi red generation is retired in this scenario. Its certainty of carbon emissions belo w 40 million tons per year is only slightly higher than the carbon-risk scenario, and slightly lower than the $45-carbon scenario.Chapter 10: Resource Stra tegy Sixth Power Plan

10-26 Figure 10-17: Probability of Meet ing Carbon Emissions Targets

0 10 20 30 40 50 60 70 80 90

C

ur

r en

t

Po

l icy Carbon Risk

$

45

Ca r bo

n P

r ice

C

o al

Re

t irement No Con s ervati o

n Coal Retirement w/ CO2Probability of Meeting Target

The analysis of these scenario s indicates that in order to reduce carbon emissions from the Northwest power system to meet a pro-rata share of the current targets adopted by some Northwest states or being proposed in federal le gislation, the region would have to acquire about 5,900 average megawatts of efficiency and signif icantly reduce the use of existing coal-fired power plants. If conservation were not available to the region in the face of carbon-pricing risk, the probability of meeting carbon reduction targets would only be 36 percent. Phasing out about half of the existing coal plants would provide a more assured reduction of carbon emissions at a comparable expected cost without the carbon pena lty included. There is no guarantee that coal retirement would be a substitute for carbon pricin g, however. Fewer coal plants would need to be retired if the region also f aced the risk of carbon penalties. But relying on response to carbon risk does not provide the same assurance of carbon reductions.

The actual use of coal-fired ge neration, when averaged over th e 750 futures in the three carbon scenarios, is fairly consistent . In 2030, the average dispatch of existing coal plants is 2,441 average megawatts in the carbon-risk scenario. The comparable numbers for the $45-carbon and
coal-retirement scenarios ar e 2,276 and 2,136, respectively. With current policy the average dispatch of coal is about double these levels at 4,157. When the frequency distribution of coal plant dispatch over the 750 futures is examined, patterns similar to the ca rbon emissions patterns in Figure 10-16 result. The c onclusion is that whether throu gh retirement or less dispatch, existing coal would only provide about half as mu ch energy and capacity to the power system as is now the case. Coal retirement provides in creased certainty of carbon emission reduction and also increased certainty a bout actions that need to be taken a nd their costs over time. In addition, it may be that dispatch of coal plants at ha lf their current levels would be an uneconomic operation for these plants. If that is the case, the carbon-pricing scenarios would imply that coal plants likely would be retired ba sed on economic considerations.Chapter 10: Resource Stra tegy Sixth Power Plan

10-27 

## VALUE OF THE HYDROELECTRIC SYSTEM

The Pacific Northwest power system emits about ha lf the carbon dioxide pe r kilowatt-hour of the
nation or the rest of the western states. This is due to the large role played by the hydroelectric system of the region. To illustrate the value of the hydroelectric system, a scenario was run to examine the effects of removing the lower Snak e River dams on power system costs and carbon emissions. The results of the scenario, however , could apply to other changes that reduce the capability of the hydroelectric system for any reason.

The lower Snake River dams provide 1,110 average megawatts of energy under average water conditions, about 5 percent of regional annual el ectric energy needs. In addition, the dams provide 3,500 megawatts of shor t-term capacity, a little more than 10 percent of the total hydroelectric system capacity, and as part of the Automated Ge neration Control (AGC) System, they provide system reserves to maintain the re liability of the power supply. They also provide reactive support for the stability of the transmission system.

The effects of removing the capability of the lo wer Snake River dams are mainly determined by the replacement resources that would be requir ed for the power system to duplicate the energy, capacity, real-time load following, stability rese rves and reactive support currently provided by the dams. To examine the effects on energy and capacity, the generating capability of the dams
was removed from the carbon-risk scenario of th e Sixth Power Plan. For this scenario, it was assumed that the power produced by the dams was removed in 2020 and the energy and capacity were replaced by other resources selected by the regional portfolio model. That is, given the reduced energy and capacity of the hydroelectric system a low-cost and low-risk portfolio of new and replacement resources is developed. Th e changes in cost, car bon emissions, risk, and average retail electricity rates are shown in Table 10-3. The effects analyzed include the replacement resources for the assumed loss to th e power system of only the energy and capacity
of the Snake River dams. No estimate was made of the cost of replacing the other services provided by the dams. There are many other imp lications and costs of dam removal including the cost of removing the dams, future operati ng cost and replacement savings, substitution of other transportation modes for barge transportati on (including fish trans portation), changes in irrigation sources, and other factor s. These were addressed most completely in the Corps of Engineers EIS on the Lower Snake River Juvenile Salmon Migration Feasibility Study

, 3 and have not been included in this analysis.

3 U.S. Army Corps of Engineers. Lower Snake River Juvenile Salmon Migration Feasibility Study 2000. http://www.nww.usace.army.mil/lsr/Chapter 10: Resource Stra tegy Sixth Power Plan

10-28 Table 10-3: The Effect of the Dam Removal Scenario
Carbon Risk Dam Removal Change Cost (billion 2006$ NPV) With Carbon Penalty Without Carbon Penalty 78.9 63.9 85.8 68.1 + $6.9 (+8.7 %) + $4.2 (+6.5 %) Risk (TailVar90 Billion 2006$ NPV)

With Carbon Penalty 123.5 135.6 + $12.1 (+ 9.8 %) Retail Rates (levelized 2006$ Per MWh) With Carbon Penalty Without Carbon Penalty 75.6 70.5 77.0 71.3 + 1.4 (1.9%) + 0.8 (1.1%) Carbon Emissions (Gen) (Million Tons/Year) 39.7 42.7 + 3.0 (+7.6 %)

Dam removal increases the carbon emissions, cost, and risk of the power system. The projected changes to the power system to accommodate the loss of hydroelectric capability are not a simple energy and capacity replacement. Sm all increases in conservation and renewable resources occur in this scenario, but the primar y replacement of the dams is provided by changes in the construction of new gas-fired generating plants, changes in the operation of existing and new generating plants, and changes in net exports . Existing natural gas- fired and coal-fired generation is used more intensively. In a ddition, the region exports less energy and imports more. The combination of these changes ma kes up for the lost 1,100 average megawatts of energy. Table 10-4 summarizes the average repl acement resources; however, the average hides a wide variation in responses depending on the future that is encountered.

Replacement of the lower Snake River dam en ergy and capacity results in increased carbon emissions of 3.0 million tons year , a 7.6 percent increase compared to emissions in the carbonrisk scenario. To place this number in context, it is an amount five times greater than the amount of carbon saved by renewable por tfolio standards between th e carbon-risk and the no-RPS
scenarios. Increased carbon emissions result because without the dams the resource strategy includes more options of additional new gas- fired generation and builds the options more frequently. In addition, existing carbon-producing resources are dispat ched more often. In total, Table 10-4 shows that 1,103 average megawatts w ould be required to replace the dams with 437 average megawatts coming from carbon-producing resources, not including increased imports that would also most likely come from carbon-producing resources

Table 10-4: Replacement of Lower Snake Dam Energy

Replacement Resource Average Change in Energy Existing Natural Gas + 91 Existing Coal + 149 New Natural Gas + 197 Conservation + 145 Renewables and Other - 10 Net Imports (reduced exports and increased imports) + 531 Total Energy Replaced on Average = 1,103

The changes in net present value system cost s hown in Table 10-3, while appropriate for regional electricity planning comparisons, hi de significant changes in costs and their allocation over timeChapter 10: Resource Stra tegy Sixth Power Plan

10-29 and among utilities and consumers in the region. Figure 10-18 shows the annual pattern of cost changes for the dam-removal scen ario. Annual cost of the po wer system increases in 2020 by over $530 million and remains higher. Further, because the lower Snake River dams serve Bonneville public-utility customer s, those utilities and their consumers would bear the cost increases. Using a rate-making rule of thum b that a $65 million to $80 million cost increase translates into a $1 per megawatt-hour increase in Bonneville rates, a $530 million increase in Bonneville costs would raise rates by betw een $6.60 and $8.15 per megawatt-hour. Based on Bonneville’s priority firm rate of $28 per me gawatt-hour, dam removal causes an increase of 24 percent to 29 percent.

Figure 10-18: Annual Cost Changes for the Dam-Removal Scenario

0 100 200 300 400 500 600 700

201 0

2011 2012 20

13 2014 2015 2

016 2

017 20

18 2019 2020 2

021 202 2

202 3

2024 2 025 20

26 2027 2028 2

029Millions2006$Chapter 10: Resource StrategySixth Power Plan10-30Figure 10-19: Summary of Scenario ResultsLeast RiskScenario Carbon Risk Current Policy No Policy No RPS $45 CO2 Cost Coal Retirement Coal Retire w/CO2 No Conservation Dam RemovalLeast Risk Least Risk Least Risk Least Risk LeastRisk Least Risk Least Risk Least Risk Least RiskL813LR L813g L813i2 L813h2 L813d L813b L813j L813a L813kCOST & RISKNPV Cost (Bil. 2006$) (w/ carbon penalty)78.9 56.1 51 77 85.7 64.3 80.3 116.2 85.8NPV Risk (Bil. 2006$)123.5 83.4 82.6 123.3 121.1 96.4 125 185.7 135.6NPV Cost (Bil. 2006$) (w/o carbon penalty)63.9 56.1 51 61.6 64.2 64.3 61.9 87.8 68.1RATES (levelized 2006$/Mwh) Least Risk Current Policy No Policy No RPS $45 CO2 Cost Coal Retirement Coal Retire w/CO2 No Conservation Dam RemovalRetail Rates (w/o carbon penalty)71 70 68 70 72 72 71 67 71Retail Rates (w/ carbon penalty)76 69 68 75 79 72 76 73 772010-29 Growth rate of rates (w/o carbon penalty0.4% 0.2% 0.0% 0.2% 0.2% 0.6% 0.4% 0.7% 0.5%% change levelized from Carbon Risk scenario (w/o)-1.0% -3.0% -1.0% 2.0% 2.0% 1.0% -6.0% 1.0%MONTHLY RESIDENTIAL BILLS (2006$) Least Risk Current Policy No RPS $45 CO2 Cost Coal Retirement Coal Retire w/CO2 No ConservationMonthly Residential Bills (w/o carbon penalty)797877788080798279.00Monthly Residential Bills (w/ carbon penalty)847877848880849185.002010-29 Growth rate of bills (w/o carbon penalty-0.70% -0.9% -1.0% -0.9% -0.9% -0.5% -0.7% 0.9% -0.6%% change levelized from Carbon Risk scenario (w/o)-1.0% -3.0% -1.0% 2.0% 2.0% -1.0% 5.0% 1.0%CARBON2030 Emissions (Generation Based, MMtpy) adjusted39.7 56.3 60.3 40.3 37.0 36.3 37.7 57.0 42.72030 Emissions (Use Based, MMtpy) adjusted29.0 42.0 50.0 31.0 28.0 28.0 27.3 60.0 35.0RESOURCESTotal Conservation (Average Development)5895 5572 5452 5966 5933 5825 5903 0 6040Renewable Resources (Forced in if RPS)1453 1480 311 1008 1450 1459 1452 2049 1443CCCT (Amount Optioned)Earliest Option3402 1512 3780 2268 1890 756 378 3780 378Earliest Construction Date2019 2019 2019 2019 2019 2015 2013 2013 2017Maximum Optioned3402 1512 3780 2268 1890 3024 4158 10962 4536Average Built991 299 909 704 551 1027 1243 4024 619SCCT (Amount Optioned)Earliest Option162 648 648 648 162 162 162 162 0Earliest Construction Date2015 2015 2017 2017 2017 2015 2021 2009Maximum Optioned648 1620 1620 1458 1620 3240 489 2916Average Built122 236 355 288 329 1062 93 961Demand Response44 4 4 4 4 4 9 4Average Market Purchases-1977 -2751 -1990 -1784 -1772 -1648 -1893 344 -1446Total New Energy8465 7591 7031 7970 8267 9377 8695 7043 8106Sixth Northwest Conservation and Electric Power Plan 

# Chapter 11: Climate Change Issues

Summary of Key Findings........................................................................................................ ...... 1 Background..................................................................................................................... ................ 2
The National View.............................................................................................................. ........ 3 The Pacific Northwest Regional View ....................................................................................... 4
Actions to Reduce Greenhouse Gas Emissions .............................................................................. 6
Policies to Reduce Greenhouse Gases ............................................................................................ 9
Mandates....................................................................................................................... .............. 9
Tax Incentives................................................................................................................. .......... 10 Cap-and-Trade Programs......................................................................................................... . 10
Carbon Taxes ................................................................................................................... ......... 11 Current Policies and Goals Affecting the Pacific Northwest........................................................ 11
International Initiatives ...................................................................................................... ....... 12
Federal Policies............................................................................................................... .......... 12 Environmental Protection Agency Role ............................................................................... 12 Legislative Efforts............................................................................................................ ..... 13 Regional Policies .............................................................................................................. ........ 13
State Policies................................................................................................................. ............ 14
Greenhouse Gas Emission Reduction Goals......................................................................... 14
Renewable Portfolio Standards............................................................................................. 14
Carbon Dioxide Emission Performance Standards................................................................... 15 Evaluating Carbon Strategies................................................................................................... ..... 16



## SUMMARY OF KEY FINDINGS

Climate change presents a daunting challenge for re gional power planners. There are at least two ways in which climate can affect the power plan. First, warming trends will alter electricity demand and change precipitation patterns, rive r flows, and hydroelectric generation. Second, policies enacted to reduce green house gases will influence future resource choices. There remains a great deal of uncertain ty surrounding both of these issues . This chapter describes how current and potential new policies affect the pl an’s resource strategy and what actions will be needed to achieve greenhouse gas emission-reduc tion goals. The issue of potential changes to electricity demand and hydroe lectric generation is discus sed in Appendix L.

The focus of climate policy, especially for the pow er sector, will be on carbon dioxide emissions. Nationally, carbon dioxide accounts for 85 percent of greenhouse gas emissions, with about 38 percent originating from electric ity generation. For the Pacific Northwest, the power generation share is only 23 percent because most of our el ectricity comes from hydroelectric generation. Analysis by others has shown th at substantial and inexpensive reductions in carbon emissions
can come from more efficient bui ldings and vehicles. More expe nsive reductions can come from substituting non- or reduced-carbon electricity generation such as renewable resources, natural gas, and nuclear, or from sequestering carbon.

Reductions in carbon emissions can be encouraged through various policy approaches such as regulatory mandates (e.g. renewabl e portfolio standard or emission standards), emissions capand-trade systems, emissions taxation, and effici ency-improvement programs. Climate changeChapter 11: Climate Change Issues Sixth Power Plan

11-2 policies enacted in the Northwest states have focused on renewable energy and new generation emission limits. National and Western proposa ls have focused on cap-and-trade systems, although none have been implemented successf ully. Although carbon taxes are easier to implement than cap-and-trade systems, none have been proposed.

Washington and Oregon have adopt ed specific greenhouse gas reduction targets. Similar targets exist for the Western Climate Initiative and in pr oposed national legislation. These goals imply reductions of 30 to 40 percent from 2005 levels by 2030. The Council’s plan explores, through various scenario analyses, what actions must be taken to meet these targets in the most costeffective manner. There are four critical elements to those actions . First is acquiring all of the efficiency improvements (which ar e significant) indentified in th is plan’s resource strategy. Second is reducing reliance on coal-fired generation to about half of curre nt levels. Third is meeting renewable portfolio standards that already exist in three of the four Northwest states. Finally, the region needs to pres erve the capability of the hydroe lectric system to the greatest extent possible within the limits of fish and wildlife and other obligations.



## BACKGROUND

Greenhouse gases include a family of gases that a ffect the ability of the Earth’s atmosphere to
absorb or reflect heat. 1 These include carbon dioxide, methane, nitrous oxide, and man-made chlorofluorocarbon refrigerants. Different gases ha ve different effects on warming and are rated as to their global warming potential. Carbon dioxide, which has become almost synonymous with greenhouse gases, has the least global wa rming potential. Many other gases have global warming potential thousands of tim es greater than carbon dioxide. Nevertheless, carbon dioxide has become the primary focus of climate change policy since it accounts for more than threequarters of the world’s greenhouse gas emissions. In the U.S., carbon accounts for 85 percent of emissions, and it is a growing source. Figure 11-1 shows that it is the primary source of greenhouse gas emissions growth in the United St ates since 1990. Levels of emissions from most other greenhouse gases have been stable or declining. Even carbon dioxide emissions, although growing in total, have declined rela tive to population and gross domestic product growth in the United States.

Declining carbon dioxide emissions per dollar of gross domestic product have been due to a changing mix of economic activity and improved ener gy efficiency. Burning fossil fuel accounts for 94 percent of U.S. carbon dioxide emissions. Therefore, declining ca rbon dioxide emissions reflects a corresponding declin e in energy use per dollar of gross domestic product.

1 The source of information for much of the following discussion is from the Environmental ProtectionAdministration. Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2006. April, 2008. USEPA #430-R08-005. http://www.epa.gov/climatechange/emissions/usinventoryreport.htmlChapter 11: Climate Change Issues Sixth Power Plan

11-3 Figure 11-1: Sources of U.S. Greenhouse Gas Emissions, 1990 to 2007

0.0 1,000.0 2,000.0 3,000.0 4,000.0 5,000.0 6,000.0 7,000.0

1 99

0

1991
1 99

2

1 9 93

1 994
1 99

5

1996
1 99

7

1 9 98

1999 2 00

0

2 0 01

2 002 2 0 03

2004 2 00

5

2 0 06

P 2 00

7Gigatons CO2e

Carbon Dioxide

Methane

Nitrous Oxide
HFCs, PFCs, and SF6

Source: U.S. Energy Information Administration



## The National View

Electricity generation is the larg est source of carbon dioxide emissi ons in the U.S. Electricity generation accounted for 38 per cent of carbon dioxide emissions in 2005 (Figure 11-3). The next largest sector was trans portation at 28 percent, followed by the industrial sector at 20 percent. Other significant sect ors include agriculture , residential, and commercial. However, electricity is generated for use in other sector s, too, and when emissions are added to those sectors, a different allocation results. When carbon emissions are connected to human activities, transportation becomes the largest carbon-emitting sector. Figure 11-2 shows the sources of carbon dioxide emission by end- use sector in the U.S.

This implies that to reduce carbon dioxide emissi ons from the electricity sector, policies should address both electricity genera tion and energy efficiency. Impr oved energy efficiency reduces the need to generate electric ity in the first place. Improved efficiency of generation and transmission technologies, changing the mix of ge neration from coal to natural gas, substituting renewable non-carbon emitting sources of generati on, or various strategies to sequester the carbon dioxide emissions are all op tions. Policies should target both sides of the electricity equation, with priority given to the lowest-cost appro aches. Furthermore, policies should also
address emissions from the direct use of fossil fuel in other sectors, including transportation.Chapter 11: Climate Change Issues Sixth Power Plan

11-4 Figure 11-2: Carbon Dioxide Emissions by Sector, 2006

Transportation
33%

Industrial
28% Residential
21%

Commercial

18%

Note: Electricity generation emissi ons allocated to end use sectors Source: U.S. Environmental Protection Agency



## The Pacific Northwest Regional View

The sources of carbon emissions in the Pacific Nort hwest are not typical of the U.S. Figure 11-3 compares the shares of carbon dioxide emissions from economic sectors for the U.S. and the four Northwest states. Unlike Figure 11-2, emissions from electricity generation are included in the electric power sector in Figure 11-3. In the Pacific Northwes t, the share of energy-related carbon dioxide emissions from electric pow er generation is much smaller than for the U.S. For the U.S., electricity generation is the la rgest source of carbon dioxide, but in the Pacific Northwest, transportation is the larg est. The reason, of course, is the dominance of the hydroelectric system in Northwest’s electricity supply.

The years 1990 and 2005 are frequently used as benchmarks in policies for the control of greenhouse gases. 2 The 1990 production of carbon dioxide from the Pacific Northwest power system is estimated to have been about 44 million tons, based on electricity production records of that year. Load growth, the addition of fossil fuel generati ng units, the loss of hydropower production capability, and the retirement of the Trojan nuclear plant re sulted in growing carbon production over the next 15 years. By 2005, th e most recent year for which electricity production or fuel consumption data are availa ble, carbon production incr eased 52 percent to 67 million tons (Figure 11-4). This is appr oximately the carbon output of 23 400-megawatt

2 For example, California Assembly Bill (AB) 32, passed by the legislature and signed by the governor in 2006, calls
for enforceable emission limits to achieve a reduction in CO 2 emissions to the 1990 rate by 2020. Washington Governor Gregoire’s climate-change execu tive order includes the same target for CO 2 reductions. Oregon House Bill 3543, passed by the legislature and signed by Governor Kulongoski in August, declares that it is state policy to
stabilize CO 2 emissions by 2010, reduce them 10 percent below 1990 levels by 2020, and 75 percent below 1990 levels by 2050. The goal of the Western Climate Initiative is to reduce greenhouse gas emissions to 15 percent below 2005 levels by 2020.Chapter 11: Climate Change Issues Sixth Power Plan

11-5 conventional coal-fired power plants, 56 400-megawa tt gas-fired combined-cycle plants or about 11.7 million average U.S. passenger vehicles.

Figure 11-3: Energy Carbon Emissions by Sector, 2005

Regional carbon production estimates from 1995 through 2005, shown in Figure 11-4, are based on the fuel consumption of Northwest power pl ants as reported to the Energy Information Administration (EIA). Because fuel consumption data were not available before 1995, estimates for 1990 through 1995 are based on plant electri cal output as reporte d to EIA and staff assumptions regarding plant heat rate and fu el type. Estimates based on plant electrical production are likely somewhat less accurate than estimates based on fuel consumption because of multi-fuel plants and uncertainties regarding pl ant heat rates. However, the two series of estimates are within 2 percent in the “overlap” year of 1995.Chapter 11: Climate Change Issues Sixth Power Plan

11-6 Figure 11-4: Growth of CO 2 Emissions from Electricity Generation in the Pacific
Northwest

0 10 20 30 40 50 60 70 80

1990 1992 1994 1996 1998 2000 2002 2004 2006Annual CO2 Production (MMtCO2)

0 5000 10000 15000 20000 25000Annual Energy Production (aMW) CO2 - Based on fuel consumption
CO2 - Based on generation

Hydro Generation
Fossil generation

Annual hydropower conditions can greatly aff ect power system carbon production. Average hydropower production in the Northwest is abou t 16,000 average megawatts. As shown by the plot of Northwest hydropower production in Figure 11-4, the 1990 water year was nearly 17,000 average megawatts, slightly better than average. Other factors being e qual, this would have slightly reduced carbon production that year b ecause additional hydroelectric generation would have displaced thermal plant operation. Conversely, hydro producti on in 2005 was about 13,800 average megawatts, a poor water year. Other f actors being equal, this would have increased thermal plant dispatch, raising carbon producti on. This effect of hydropower generation on thermal plant dispatch and carbon pro duction is apparent in Figure 11-4. 3

If the estimated CO 2 production in 2005 were normalized to average hydropower conditions, emissions would have been 57 million tons instead of 67 million tons, a 29 percent increase over the 1990 rate. Current targets have not been clear about this adju stment, but without adjustment, a goal based on 2005 emissions would be much easier to meet than one based on 1990. In the power plan, the Council has used the adjusted-t o-normal hydro value for 2005 so that the number will be comparable to forecasts of average emissions in the plan’s scenarios. It should be clear, however, from the discussion and Figure 11-4 that average carbon emissions will disguise significant carbon emissions sensitivit y to hydro conditions in the region.



## ACTIONS TO REDUCE GREENHOUSE GAS EMISSIONS

From a broad perspective, there are three things we can do to reduce carbon dioxide emissions: generate electricity from lower or zero carbon-em itting fuel, use less electr icity, or sequester or

3 In Figure 11-4, it is evident that Northwest thermal generation does not decline as much as Northwest hydro generation increases in above average water years, e.g. 1994 - 1997. This is likely due to the fact that the abundant hydropower of good water years creates a regional energy surplus that can be sold out of the region where it displaces thermal generation, which often consists of older, less efficient gas-fired units.Chapter 11: Climate Change Issues Sixth Power Plan

11-7 offset carbon that is release d. In 2007, McKinsey and Comp any studied how much greenhouse gas reduction was possible in the U.S. and what it might cost. 4 The McKinsey report looked at alternative actions to reduce greenhouse emi ssions. They assumed that without actions, greenhouse gas emissions would grow from 7.2 billi on metric tons to 9.7 billion metric tons by 2030. They then analyzed ways to reduce 2030 em issions by 3.0 billion metric tons, which was characterized as the mid-range of reduc tions sought in proposed legislation.

They estimated that about 40 percent of reductions could be done at no cost. Nearly all of this came from improved energy efficien cy in buildings or vehicles. The remaining 60 percent of greenhouse gas reduction came from an array of actio ns that increased in cost as reductions grew. The most expensive option to achieve the 3.0 billion metric ton reduction of 2030 emissions was estimated to cost $60 per ton.

All of the actions included in th e McKinsey analysis were placed in to five categories: buildings and appliances, transportation, industry, carbon sinks (or sequestr ation), and power generation.
In the case where carbon emissions were reduced by 3.0 billion tons, the sources of reductions are shown in Figure 11-5. As with the case for Figure 11-2, emission reductions from energy efficiency are counted in the sect or where electricity is consumed.

Figure 11-5: Estimated Sources for a 3 Bill ion Ton Reduction of GHG Emissions by 2030

Buildings and Appliances

24%

Transportation

10%

Industry

21% Carbon Sinks

17% Power
Generation

28%

There are some interesting observations to make about the McKinsey re sults. Although a great deal of the policy discussion on carbon reduction focuses on the electricity generation sector, only a quarter of the actions identified in the McKi nsey report are electric ity generation changes. Further, the electricity gene ration changes are among the more expensive actions, and they
include actions such as renewa ble generation and carbon capture and sequestration, which cannot be implemented easily in the near term.

Another focus of policy speculation is hybrid vehicl es. In the McKinsey analysis, it is the most expensive alternative shown (ar ound $90/ton) and it has relative ly small potential for carbon

4 McKinsey & Company. Reducing U.S. Greenhouse Ga s Emissions: How Much at Wh at Cost? U.S. Greenhouse Gas Abatement Mapping Initiative, Executive Report. December 2007.Chapter 11: Climate Change Issues Sixth Power Plan

11-8 reduction. The plug-in hybrid optio n was not needed to reach the 3.0 billion ton reduction case. However, improved efficiency of conventional vehicles has far more potential to lower carbon emissions in the short-term, and it is less expensive than PHEV.

If the goal is to stabil ize greenhouse gas concentrations in the atmosphere, and if the climate change science is correct, policy decisions would not be a question of which mitigation strategies to pursue, but rather how to pursue all possible actions. The reductions in emissions that the McKinsey report addressed were for recent clim ate change policy proposals, but they do not
reach the reduction levels needed to stabilize warming trends identified by climate scientists. For example, the Intergovernmental Panel on Climate Change estimated that greenhouse gas
emissions would need to be reduced to about one-quarter of today’s emissions by 2100 to stabilize their atmospheric concentrations.

There have been many studies on the costs of pa rticular climate change policies. The usual purpose has been to try to estimate the price of carbon that is likely to be associated with a policy. EcoSecurities Consulting Limited conduc ted a study for the Council to determine a range of likely carbon costs for the plan’s analys is. EcoSecurities reviewed many studies and provided a set of alternative estimates based on their models of supply curves for carbonmitigation actions. In addition, Point Carbon re viewed the results of seven studies of the
Lieberman-Warner bill for th e Bonneville Power Administrati on, and used the studies to estimate a reasonable range of expected carbon prices under the proposed cap-and-trade policy.

Carbon price estimates under cap-and-trade programs are very sensitive to different assumptions about such things as the leve l of the carbon emissions cap, the use of offsets, banking and borrowing provisions, and the geographic scope of trading. Price forecasts for the 2025 to 2030 time period varied from near zero to well over $100 per ton of carbon emissions. However, the more plausible range of prices was from roughl y $10 to $80. The EcoSecurties report estimated that carbon prices might need to reach about $50 a ton by 2030 to move toward the Intergovernmental Panel on Climate Change goal of stabilizing emissions concentrations by 2100. Point Carbon’s assessment suggested that pr ices would escalate rapidly in years beyond 2030, although they regard their forecasts that fa r into the future as highly speculative and unlikely to consider technological developments that may occur.

For the Sixth Power Plan, the Council considered a range of possible car bon costs between zero and about $100 per ton, with an average cost of about $47 per ton by the end of the study’s horizon. This possible but uncertain cost of car bon has a significant influence on the plan’s resource strategy. Energy efficiency, renewabl e generation, natural gas-fired generation, coal (with or without carbon sequestration), and advan ced nuclear power all compete to provide the lowest-cost and least-risky res ource portfolio. Even before accounting for the effects of uncertainty and risk on resource costs, it is cl ear that improved efficiency is available in significant amounts and at low co st without adding carbon or fuel price risks for the region. Natural gas, wind (that can be developed w ithout significant transm ission expansion), and possibly some small quantities of other curren tly available renewable technologies are more expensive. Many other renewa ble resources--coal with carbon separation and sequestration and advanced nuclear--may become available within the Council’s planning horizon, but they are not currently available or are very expensive.Chapter 11: Climate Change Issues Sixth Power Plan

11-9 To achieve significant reductions in the region al power system’s carbon emissions, simply reducing or stopping the growth of carbon emissi ons will not be enough. As shown in Figure 11- 6, existing coal-fired power plants account fo r about 88 percent of the region’s emissions. Therefore, the region could not reduce its power system emissi ons below 1990 levels, as some targets require, if the region’s coal plants continue to operate as they do now. Part of the solution to aggressive carbon emission reduc tions would have to include ch anging the role of existing coal-fired generation. This would occur as a matter of economics if carbon penalties are high enough and natural gas prices low enough. Natural gas-fired generation woul d begin to displace coal-fired generation in the dispat ch order. In addition, some olde r coal-fired plants that need
additional investment to continue or meet more stringent environmental requirements may
choose to close rather than face the un certainty of unknown future carbon costs.

Figure 10-6: Sources of CO 2 Emissions from the Northwest Power System, 2005

Biomass

Coal

Geothermal

Natural Gas

Petroleum

Petroleum Coke

Unknown

Nuclear Hydro

Wind



## POLICIES TO REDUCE GREENHOUSE GASES

There are many possible policy approaches to re duce carbon emissions: cap-and-trade programs, direct taxation of emissions, regulatory progr ams that limit emissions or require non-emitting resources to be developed, and efforts to impr ove energy efficiency. Most recently, proposed national legislation has focused on cap-and-trade pr ograms, but none has been passed to date. At the regional and state level, renewable portfolio standards and limits on the emissions of new power plants have been the prevailing policie s. The Council has primarily focused on energy efficiency, and states, utilities, and the federal government have in itiatives to improve efficiency as well. Most of these efficiency programs existed well before the climate change issue was prominent, simply because improved efficien cy was cheaper than building new electric generating plants and it contribute d to reduced oil imports. Each approach has advantages and disadvantages.



## Mandates

Mandates direct companies and i ndividuals to acquire or prod uce equipment that meets an approved standard of energy efficiency or uses approved types of energy. One example is theChapter 11: Climate Change Issues Sixth Power Plan

11-10 Corporate Average Fuel Efficiency standard for ca rs and light trucks. It has been in place since 1975 and imposes fines on car manufacturers whose products do not meet the standard. Other examples are appliance efficiency standards and the region’s building codes, which have had an energy-efficiency component for more than 20 years.

More recently, Washington, Oregon, and Montana in the Pacific Northwest and a number of states elsewhere in the country have passed laws (renewable portfolio st andards) that require utilities to increase generation fr om renewable resources. These or related laws have in some cases also required generators that use non-renewable fuel to keep their emissions below a maximum emissions per kilowatt-hour standa rd (e.g., Washington and California).

Mandates have the advantage of being simple and are fairly easy to enforce. They have the disadvantage that they are inflexible in the face of changing technology or other conditions. Unless made sufficiently flexible, a mandate would focus policy on only one approach to reducing carbon emissions and not consider other al ternatives that might be more effective or less expensive.



## Tax Incentives

Tax incentives will help by reducing the overall inve stment in preferred resources and equipment through accelerated depreciation, ta x credits, or various forms of tax exemptions. Such tax incentives have been extended to hybrid cars, wind generators, energy-efficient equipment and structures, renewable energy equipment pur chases, and renewable energy equipment manufacturing facilities.

Tax incentives can also increase the value of output from preferred equipment such as winddriven generators by granting tax credits (e.g. the production tax credit) based on the amount of electricity produced by the generators. Compared to investment tax cr edits, production credits have the advantage in that the credit is ba sed on the actual generation, so that producers are encouraged not only to invest in preferred equipment, but also to produce as much electricity as possible with it.



## Cap-and-Trade Programs

A cap-and-trade policy sets a cap on the total amount of emissions allowed in the covered territory. The cap is enforced by issuing allowa nces in the amount of the cap and then requiring
emitters to surrender allowances in the amount of their emissions. The strategy is to reduce the amount of the cap and the equivalent allowances over time to reduce emissions. Emitters are allowed to trade allowances to encourage thos e who can reduce emissions easily and cheaply to do so and profit by selling their surplus allowances to other emitters. Emitters may be allowed to
“bank” or “borrow” allowances fr om year-to-year if they have a surplus or deficit of allowances in a given year. Cap-and-trade programs may include provisions for offset allowance credits resulting from taking certain emission reducti on actions outside the scope of the regulated system.

A cap-and-trade policy to control emissions of su lfur dioxide and nitroge n oxide was established as part of the 1990 Clean Air Act. This policy is generally regarded as a success, resulting in
faster reductions in sulfur dioxi de emissions at lower costs th an anticipated. Cap-and-tradeChapter 11: Climate Change Issues Sixth Power Plan

11-11 programs have been included in proposed federa l legislation to contro l greenhouse gas emissions
and are also included in Western Climate Initiati ve discussions. The European Union Emission Trading System has been in place since 2005, ca pping a substantial fracti on of Europe’s total greenhouse gas emissions and providing e xperience with this policy approach.

Compared to mandates and tax incentives, a cap-and-trade policy has the advantage of flexibility. Emitters can pursue a variety of strate gies to reduce their own emissions or they can pay other emitters to reduce. They can choose the strategy that will minimize their cost (and the societal cost) of compliance. Another advantage of cap-and-tr ade policy compared to mandates and tax policies is that the cost of emission allowa nces is incorporated into the retail prices of energy, at least theoretically providing appropriate pri ce signals to consumers.

As a policy with the goal of reducing emissions of greenhouse gases, cap-and-trade programs make the physical target for emissions explicit. As a result, the policy sh ould meet the target reliably, but emission prices and total costs of emission reductions could be volatile and hard to predict. In contrast, carbon ta x policy has a more predictable total cost, but a less predictable
total reduction in emissions.

Finally, cap-and-trade programs need to develop a market to trade emission allowances. The market mechanism offers the potential for emi ssion reductions at low costs. But developing a market to trade newly-created assets like emissi on allowances requires careful consideration to ensure that the market will function as expected.



## Carbon Taxes

A carbon tax would likely apply no t only to carbon, but to all gr eenhouse gases in proportion to their climate-changing effects, and would tax emi ssions at a level to control and mitigate climate change.

A carbon tax has the advantage of being easier to administer than a cap-and-trade system and the cost is predictable, but the carbon reductions are less certain. A cap-a nd-trade program makes carbon reductions more predictabl e, but it is complex to admini ster and the total cost is unpredictable.

As a practical matter, this di stinction between a carbon tax an d cap-and-trade program may be
less than it seems. Given the current state of knowledge about the effects of climate change and the technological choices availa ble for reducing emissions, it seems inevitable that whatever initial cap is chosen for the cap -and-trade program, or whatever initial level is chosen for a carbon tax, new information that becomes availabl e over the next several decades will require adjustments in the national and global strategy to control greenhouse gases.



## CURRENT POLICIES AND GOAL S AFFECTING THE PACIFIC
NORTHWEST

At present, carbon reduction polic ies regionally, nationally, and globa lly are still very much in a state of flux. Reduction goals ra nge from stabilizing emissions at current levels to reducing
emissions to 1990 levels or below.Chapter 11: Climate Change Issues Sixth Power Plan

11-12 

## International Initiatives

Significant international initiatives targeted at climate change can probably be dated from 1992,
when the United Nation’s Framework on Climate Ch ange was negotiated. Since then, there have been several significant milestones in internat ional action, including the Berlin Mandate in 1995, calling for emission targets for developed countri es, and the Kyoto Protocol in 1997, which set reduction targets for developed countries to m eet by the 2008-2012 period. The Kyoto Protocol, in spite of the withdrawal of the U.S. in 2001, has been ratified by 182 countries, including 37
industrialized countries that account for over 60 percent of the emissions from developed
countries.

The European Union’s Emissions Trading Systemhas been functioning since 2005. It is a capand-trade system currently covering sources that are responsible for about half of the European Union’s total carbon dioxide emissions. The sy stem’s first three years of operation (2005-2007) were intended to test the functioning of the market mechanism itself rather than to achieve significant reductions. The system has experienced episodes of price vol atility, which has been attributed to imperfect data and the limited provision for banki ng emission allowances. Some electric power generators appear to have received windfall prof its, which has focused attention on the regulatory treatment of those generators . The system will gradually expand to include emissions from more sources constituting a bigger share of total emissions over time.

The Intergovernmental Panel on Climate Change 5 has identified a goal of limiting global warming to 2 degrees Celsius (3.6 degrees Fahrenhe it) and has translated that goal into emissionreduction targets for developed countries. Thos e targets call for an 80 percent to 95 percent reduction relative to 1990 levels by 2050.



## Federal Policies

Environmental Protection Agency Role
On April 2, 2007, in Massachusetts v. EPA , 549 U.S. 497 (2007), the Supreme Court found that greenhouse gases are air pollutant s covered by the Clean Air Act. The Court held that the
administrator must determine whether or not emissions of greenhouse gases from new motor vehicles cause or contribute to air pollution which may reasonably be anticipated to endanger public health or welfare, or wh ether the science is too uncertain to make a reasoned decision.

On December 7, 2009, the Environmental Protection Agency administrator signed two distinct findings 6 regarding greenhouse gases under sectio n 202(a) of the Clean Air Act:

• that the current and projected concentrati ons of six key greenhouse gases, including carbon dioxide in the atmosphere threaten the public health and we lfare of current and future generations and

5 Information on the Intergovernmental Panel on Climate Change (IPCC) can be found at http://www.ipcc.ch/

. 6 The Environmental Protection Agency findings are found in “40 CFR Chapter I Endangerment and Cause or Contribute Findings for Greenhouse Gases under Section 202(a) of the Clean Air Act; Final Rule” and were published on December 15, 2009 in the Federal Register under Docket ID No. EPA-HQ-OAR-2009-0171. The final rule will be effective January 14, 2010.Chapter 11: Climate Change Issues Sixth Power Plan

11-13 • that the combined emissions of these gree nhouse gases from new motor vehicles and new motor vehicle engines contribu te to the greenhouse gas pol lution which threatens public
health and welfare.

These findings currently do not impo se any requirements on industry or other entities. However, they are a prerequisite to fi nalizing the EPA’s proposed green house gas emission standards for light-duty vehicles, which were jointly proposed by EPA and the De partment of Transportation’s National Highway Safety Admi nistration on September 15, 2009.

These findings also are not likely to have a sign ificant adverse effect on the supply, distribution, or use of energy because they do not impose any requirements at this time. 7 There remains a possibility that the EPA could impose greenhouse ga s emission limits on electricity generators at some time in the future; however, the current ad ministration has indicated a preference to control greenhouse gases via legislation as opposed to EPA mandates.



### Legislative Efforts

There have been a series of proposals for national legislation on climate change. The most recent serves as an example of the policy being discussed. The Waxman-Markey draft legislation, entitled “The American Clean Energy and Security Act of 2009,” proposed a comprehensive strategy for energy planning and use. The legislation contained provisions to increase use of renewable energy and to improve effi ciency. It would requir e electric utilities to meet 25 percent of their load with a combination of renewable energy and efficiency improvements by 2025. In addition, it proposes creat ion of a greenhouse gas tradable allowance system that would reduce emission allowances to 83 percent lower that 2005 levels by 2050. The bill also contained numerous other provisi ons providing assistance for reducing emissions and directing EPA to take specific actions.



## Regional Policies

The Western Climate Initiative (WCI) is a broad regional effort to implement policies to reduce greenhouse gas emissions. The governors of Ore gon, Washington, and Montana have joined five other Western state governors and the premiers of four Canadian province s to implement policies that address climate change. The overall goal of the WCI is to reduce the region’s greenhouse gas emissions to 15 percent below 2005 levels by 2020. The primary policy objective of the WCI is to implement an economy-wi de regional cap-a nd-trade program.

The WCI Partners have promulgated specific design recommendations for the regional cap-andtrade program. In its first phase, beginning in 2012, the program would cover emissions from electricity production and from la rge industrial processes. The program would cover emissions of carbon dioxide and five other major greenhouse gases. In its second phase, beginning in 2015, the program would be expanded to cover em issions from the combustion of transportation fuel and fuel burned at industrial, co mmercial, and residential buildings.

The WCI’s work has made it clear that a regiona l cap-and-trade program faces problems that a national or international program does not. For example, because individual states and provinces

7 See “H. Executive Order 13211: Actions Concerning Regulations That Significantly Affect Energy Supply, Distribution, or Use.”Chapter 11: Climate Change Issues Sixth Power Plan

11-14 have significant flexibility to modify their jurisd iction’s reduction targets, the allocations are a source of potential conflict. Another example is the potential for “leakage” that can result from shifting emissions from inside the WCI to the ou tside. Such a shift would allow WCI emission targets to be met, but with no net reduction in global emissions. Leakage becomes less likely as the geographic scope of th e cap-and-trade program expands to the na tional or international level.



## State Policies

Policy initiatives at the state level to address climate change are numerous, but three types of state policy predominate: greenhouse gas reduct ion goals; renewable portf olio standards; and emission performance standards. There is a grea t deal of policy work aimed at establishing renewable energy tax credits, renewable energy feed-in tariffs, renewable energy enterprise zones, funding mechanisms for energy-efficiency projects, improved commercial and residential building codes, and others that either directly or indirectly influence greenhouse gas production, but the focus here is on policies that have the greatest releva nce to the Sixth Power Plan.



### Greenhouse Gas Emission Reduction Goals
The 2007 Oregon Legislature set greenhouse gas emi ssions reduction goals for the state. The mid-term goal is to reduce emissions to 10 percent below 1990 levels by 2020. The long-term goal is a 75 percent reduction from 1990 levels by 2050. The 2009 Legislature is considering Senate Bill 80, which would authorize the state’s participation in the WC I cap-and-trade program as a key means of reaching the future emission goals.

The 2009 Washington Legislature is also consider ing WCI cap-and-trade legislation. House Bill 1819 and Senate Bill 5735 would codify the stat e’s goal of reducing greenhouse gas emissions to 1990 levels by 2020, achieving a 25 percent redu ction by 2035, and a 50 percent reduction by
2050.



### Renewable Portfolio Standards
Since the adoption of the Fifth Power Plan, renewa ble resource portfolio standards that mandate developing certain types and amounts of resource s have been adopted by Oregon, Montana, and Washington. Similar standards have been adopt ed by Arizona, British Columbia, California, Colorado, New Mexico, and Nevada. The key char acteristics of the Paci fic Northwest states’ renewable targets are summarized in Table 10-1. The targets are s ubject to adjustments if costs
increase above certain limits.

Table 10-1: Renewable portfolio standard targets
Basic Standard
Montana 15% of IOU sales by 2015

Oregon 25% of sales by 2025 (large utilities) 10% of sales by 2025 (medium utilities) 5% of sales by 2025 (small utilities)

Washington 15% of sales 2020 + cost-effective conservation (utilities w/25,000 or more customers)Chapter 11: Climate Change Issues Sixth Power Plan

11-15 

## Carbon Dioxide Emission Performance Standards

Carbon dioxide emission performance standards have been adopted by California, Montana, Oregon, and Washington. The Northwest state sta ndards in effect at the time of this plan’s
release are as follows:

Montana: In May 2007, Governor Schweitzer of M ontana signed into law HB 25, an electric power reregulation bill. Among va rious provisions, this bill prohibits the Public Service Commission from approving electric generating units constructed after January 1, 2007 and primarily fueled by coal unless a minimum of 50 percent of the carbon dioxide produced by the facility is captured and sequestered. The requirement remains in effect until such time that uniform state or federal standards are adopt ed for the capture and sequestration of carbon dioxide. The bill further provides that an entity ac quiring an equity interest or lease in a facility fueled primarily by natural or synthetic gas is required to secure cost-effective carbon offsets
where cost-effective is defined as actions to offs et carbon dioxide that do not increase the cost of electricity produced by more than 2.5 percent.

Oregon: Since 1997, the developers of new power pl ants in Oregon have had to offset their carbon dioxide emissions to a level 17 percent below best commercial generating technology of equivalent type. In July 2009, Governor Kulong oski signed into law SB 101 to establish a new greenhouse gas emission performance standard for all long-term procurements of electricity by electricity providers. The standard will be esta blished by the state’s Department of Energy and will apply to all baseload electrical generating facilities. Baseload generating facilities are defined as facilities designed to produce elec tricity on a continuous ba sis at a 60% capacity factor or greater. The standard will require that th e greenhouse gas emissions of new baseload facilities be no greater than th e rate of greenhouse gas emissions of a combined-cycle power plant fueled by natural gas.

Washington: Since 2004, Washington has required fossi l-fueled power plants of 25 megawatts or greater to offset or otherw ise mitigate carbon dioxide emissi ons by 20 percent. In addition, RCW 80.80, signed into law by Gove rnor Gregoire in May 2007 establishes a greenhouse gas performance standard for all “long-term financial commitments” for baseload generation used to serve load in Washington, entere d into in July 2008, or later. The requirement applies whether
the source is located within or outside the stat e. Modeled on California Senate Bill 1368, the law defines baseload electrical generati ng facilities as facilities designe d to produce electricity at a 60 percent capacity factor or greater. The law adopts the initial Califor nia limit of 1,100 lbs/CO 2 per megawatt-hour, and requires that the limit be reviewed and adjusted every five years by the Department of Community Trade and Economic Development to match the average rate of emissions of new natural gas combined-cycle powe r generation turbines. The limit is likely to be
reduced on review since current natural gas combined cycle plants produce about 830 lb/CO 2 per megawatt-hour (the California limit appears to have been base d on the carbon dioxide output of an aeroderivative simple-cycle gas turbine ope rating on natural gas, not a combined-cycle turbine). The law allows up to five year s to implement a carbon dioxide separation and sequestration regime (if the technology is ava ilable), as long as average lifetime emissions comply with the emissions performance standard.Chapter 11: Climate Change Issues Sixth Power Plan

11-16 

## EVALUATING CARBON STRATEGIES

Existing climate change policies, such as th e Oregon and Washington emission reduction goals, as well as proposed future policies were factors in developing the Sixth Power Plan’s resource strategy.

The recommended actions in the Sixth Power Plan reflect existing carbon emissions policies that are assumed to continue. That is, the renewable portfolio standards that have been adopted in three states, the new generation emissions sta ndards adopted by three states, and renewable energy credits are included in the analysis and are assumed to be enforced. In addition, the plan recognizes that there are adopted goals for green house gas emissions redu ctions for Oregon and Washington, as well as proposed federal legislat ion with similar goals. Most proposed policies to attain these goals rely on some system fo r putting a cost on carbon emissions. Whether these costs are the price of emission allowances under a cap-and-trade system or some form of carbon tax, the costs imposed on the power system are a risk that the plan addresses, along with other costs and risks faced by the regional power system.

The Council’s assumptions on carbon price risk we re based on consultations with a range of utility and other analysts and reviews of studi es by others, including a report done for the Council by Ecosecurities Consulting Ltd. The assump tions are included in the regional portfolio model’s carbon risk study as a distribution of 750 carbon-price trajectories that range from zero to $100 per ton, with an expected value of about $47/ton in 2030. A partial survey of regional utilities indicated that the range of prices the Council included in its analysis is generally consistent with assumptions used in their analyses.

Tracking power system emissions in the region requires a definition on ho w to treat emissions from electricity that is importe d and exported. The emissions reported in this plan include those from generators located outside the region, but whose output is committed to serving regional load. These generators include parts of the Colstrip generation complex in eastern Montana, all of the Jim Bridger complex in Wyoming, and part of the Valmy generation complex in Nevada. This approach is referred to as “generation based.” The regiona l portfolio model also reports another approach referred to as “load based” carbon emissions. This alternative approach counts emissions associated with imports and exclude s emissions associated with the electricity exported from the region. For ease of exposition a nd comparability, most of the discussion in the plan refers to generation-based carbon coun ting. In addition, the generation-based carbon emissions are adjusted to be consistent w ith the accounting reflect ed in the Council’s 2007 carbon footprint paper. 8

There are also some complications in how to ac count for the estimated cost of carbon-pricing policies to the regional power system. The default accounting of power system costs in the Council’s models includes carbon pe nalties as though they were pa id as a tax on every ton of carbon emitted. This approach is valid for m odeling the penalties’ effect on power system development and operating decisions. Howeve r, the default accoun ting can significantly overestimate the total costs that the power syst em would recover from ratepayers, depending on the kind of carbon penalty the system faces. In particular, the current language of the U.S.

8 Northwest Power and Conservation Council, Carbon Dioxide Footprint of the Northwest Power System , November 2007. (Council Document 2007-15)Chapter 11: Climate Change Issues Sixth Power Plan

11-17 House of Representatives proposal on climate polic y includes a cap-and-trade system that grants free allowances to utilities that roughly offset their emissions until 2026. This approach would greatly reduce the cost to the power system, compared to a ca rbon tax on all emissions. To
include the effect of differen t forms of carbon penalties, the regional portfolio model has an alternative accounting that excludes the amount of tax revenues. This alternative accounting provides a better cost estimate of a cap-and-tr ade, free-allowances mechanism to the power system.

The Council’s plan provides a resource strategy th at minimizes the cost of the future power system given the policy risks. A combination of aggressive developmen t of energy efficiency, renewable resources, and in the l onger-term, new gas-fired resour ces results in a reduction of power system carbon emissions from 57 million tons per year in 2005 to 40 million tons in 2030,
which is below the 1990 emission level of 44 mi llion tons. These reductions are generally consistent with the targets adopted by Northw est states. The reduced carbon emissions depend on efficiency improvements and other low-em ission generation displacing the reliance on existing coal plants. Figure 11-7 shows the pr ojected average carbon emissions over time in the carbon risk scenario. That scenario on averag e meets or exceeds the 2020 targets adopted by Washington, Oregon, the WCI, and the Waxman/Markey proposed legislation.

Figure 11-7: Average Sixth Power Plan Annual Carbon Emissions

0 10 20 30 40 50 60

2 010 201 2 2 014 2 0 1 6 2 018 2 020 202 2 2 024 2 0 2 6 2 028Million Tons Per Year

The carbon-cost risk assumptions play an important role in these results. If only current policies are assumed in the future--and no carbon pricing policies are implemented or expected--a leastcost resource strategy would st abilize carbon emissions from the power system at around current levels. Current policies arrest the growth of carbon emissions becau se of aggressive efficiency improvements, which are cost-effective even w ithout carbon penalties, and increased acquisition of renewable generation. But existing policies wi ll not achieve the carbon emissions goals of the
WCI or of some individu al states in the region.

The cost of moving from current policy to the carbon risk scenario is significant. Responding to the risk of carbon penalties in the $0 to $100 pe r ton range increases power system costs by 14 percent. When the carbon penalty is included, the cost increase is estimated to be 41 percent.Chapter 11: Climate Change Issues Sixth Power Plan

11-18 The extent to which the carbon penalty is a net cost to the power system or region depends on how that policy is structured. Current proposed federal policy provides free emission allowances under a cap-and-trade system for many years, which would put the cost impact near the lower end of the range. If power system costs incr ease by 14 percent, average electricity revenue requirements would increase by about 2 percent compar ed to current policies. However, the cost increase would not be spread evenly among the re gional utilities and cons umers. Utilities that are more reliant on coal-fired generation would b ear a larger part of the cost of carbon emission
reduction.

To significantly lower carbon emissions from th e power system, existing coal-fired generation would have to be reduced. This is not surprisi ng since existing coal pl ants account for about 88 percent of the carbon emissions from the regional power system. In the carbon risk scenario, carbon reductions occur because these plants ar e used much less frequently. In doing so, however, maintaining the plants may not be econo mically feasible for utilities. In addition, while carbon emissions are reduced to target leve ls on average, the certainty of achieving targets is low. Depending on how some future uncerta inties unfold, such as hydro conditions, carbon prices, and other factors, emi ssions can vary greatly and need not fall below the targets.

Two alternative scenarios were analyzed that pr ovided more clarity with regard to what the region would need to do to meet a specific carb on reduction target in the 35 to 40 million tons per year range. One of those scenarios im plemented a fixed $45 per ton carbon penalty, which was sufficiently high to reach the emissions targ et. That scenario resulted in average 2030 carbon emissions of 37 million tons, 35 percent be low 2005 levels. In addition, the likelihood of attaining the desired reductions is somewhat higher than in the $0 to $100 per ton scenario.

The second of these scenarios phased out existin g coal generation until emission targets were
met. This coal retirement scenario retired a bout half of the coal-fir ed generation serving the region. Average 2030 carbon emissions were re duced to 36 million tons. Importantly, the certainty of carbon reductions is much greater in the coal retirement scenario. Replacing the energy and capacity from coal plants would in crease average power system costs by about 15 percent above the current policy scenario. While this is an alternative policy approach to consider, it would not have the br oad effect on other sectors and resource decisions that a capand-trade or tax would have. If a coal retirement policy were implemented in combination with a carbon penalty, fewer coal plants wo uld need to be retired, but th e remaining plants would still be used less frequently in res ponse to the carbon pri ces. These scenarios are discussed further in Chapter 10.

In summary, there are four th ings the region would have to do to meet existing 2030 carbon reduction targets. First, the effi ciency of electricity use has to be improved to save nearly 6,000 average megawatts by 2030. These efficiency improvements are ke y to reducing carbon emissions. In the carbon risk scenario, effi ciency improvements lower 2030 carbon emissions by 17 million tons per year. Without efficiency im provements, carbon prices modeled in the carbon risk scenario would only stabi lize emissions at the 2005 level. Second, renewable portfolio standards adopted in thre e of the four Northwest states must be implemented. These resources play a significant role by reducing the amount of carbon-emitting generation. Third, the use of coal-fired generation must be furt her reduced either by pol icy or by carbon penalties. In all three of the scenarios that meet carbon reduction goals, coal-fired generation is reduced by about halfChapter 11: Climate Change Issues Sixth Power Plan

11-19 from current levels. Finally, the region needs to preserve the capabil ity of the hydroelectric system to the greatest extent possible within th e limits of fish and wildlife obligations.

Just as coal-fired generation is the source of mo st of the power system’s carbon emissions, the regional hydroelectric system is the source of most of th e region’s energy, capacity, and flexibility supply. As a carbon-fr ee resource, it is extremely valuab le to the region. Because of the hydroelectric system, combined with the region’s past accomplis hments in energy efficiency, the region’s carbon emissions are half the nation’ s in terms of carbon emission per kilowatt-hour of energy consumption. Meeting the region’s res ponsibilities for mitigati ng the fish and wildlife losses caused by the dams has depleted the capabil ities of the hydroelectric system over time. If the region needs to further redu ce hydroelectric generation for fi sh and wildlife survival, it should do so with careful analysis of the costs, risks, and bene fits of the proposed actions. The region needs to be sensitive to the fact that further reduction in hydroelectric generation will increase carbon emissions, which will also harm fish and wildlife in the long term through accelerated climate change. For example, an analys is in the draft plan showed that removing the lower Snake River dams would undo 40 percent of the carbon reductions expected to be accomplished through the existing carbon policies in the region, while also increasing the cost of the power system.Sixth Northwest Conservation and Electric Power Plan 

# Chapter 12: Capacity and Flexibility Resources

Summary of Key Findings........................................................................................................ ...... 1 Background..................................................................................................................... ................ 2 Power System Requirements: Capa city, Energy, and Flexibility................................................... 2 Capacity: Meeting Peak Demand............................................................................................... 2 Energy: Meeting Average Demand ........................................................................................... 5 Flexibility: Providing Within-hour Balance .............................................................................. 5 Power System Operations........................................................................................................ ....... 5 Ancillary Services............................................................................................................. .......... 6 Regulating and Balancing Reserves............................................................................................ 6 Flexibility Issues Raised By Wind Generation............................................................................. 11 Response to Growing Need for Flexibility ............................................................................... 12 Institutional Changes .......................................................................................................... .. 13 Adding Flexible Capacity ..................................................................................................... 14



## SUMMARY OF KEY FINDINGS

Historically, Northwest power system planners have focused on providing sufficient energy to meet the annual energy load of the region. Largely because of the way the hydroelectric system developed, capacity, the ability to meet peak-hour load, and flexibility, the ability to rapidly increase or decrease generation out put, were not significant problems.

Today, however, focusing regional power system planning solely on annual energy requirements is no longer adequate. Changes in the seasonal shape of Northw est load, increasing constraints on the operation of the hydrosystem to meet fish requirements, and rapidly increasing amounts of variable generation, especially wind, are making in creased system capacity and flexibility a new priority.

Wind generation needs back-up, flexible resources to handle unexpected changes in its output. While the problems appear daunting, particularly in integrating new wind generation with a more constrained hydrosystem, there are solutions. Th e first step is to change system operating procedures and business practices to more fully utilize the inherent flexibility of the existing system. The Council believes these changes will be significantly cheaper to achieve, and can be implemented sooner than adding additional generati ng capacity solely to provide flexibility. It will also set the stage for dete rmining how much flexibility wi ll ultimately be needed from new generation.

Actions for these operating and business practi ce changes include: es tablishing metrics for measuring system flexibility; developing methods to quantify the flexibility of the region’s existing resources; improving forecasting of the re gion’s future demand for flexible capacity; improving wind forecasting and scheduling; transitioning from the current whole-hour scheduling framework to an intra-hour scheduling framework; and increasi ng the availability and use of dynamic scheduling. Fully implementing these improvements may also require physical upgrades to transmission, communication, and c ontrol facilities, though the cost of these upgrades is expected to be relativ ely small compared to the cost of adding new flexible capacity.Chapter 12: Capacity and Flexib ility Resources Sixth Power Plan

12-2 Because the reliable operation of the power system depends on agreement on these operating procedures, they cannot be changed overnight. However, significant studies and discussions are underway to achieve these changes and the C ouncil urges they be supported by the region’s utilities and power producers.

The next step is to ensure that resources added to meet peak-hour load ar e also flexible enough to respond to unexpected changes in wind plant out put. These solutions should be sought in a sequence that makes economic sens e. Actions include: consider ing rapid-response natural gasfired generators, pumped-storage hydro plants and other storage resources, utility demand response programs and other potential smart grid applications, and geographic diversification of wind generation as options to meet the region’s future demand for flexibility. Some balancing authorities, Bonneville especially, may need additional flexibility resources, either from better use of existing resources or from new resources, solely for integration of wind generation that meets load in other balancing authorities.



## BACKGROUND

The fundamental objective of power system opera tions is to continuously match the supply of power from electric generators to the customers’ load. Histor ically, for resource planners, the balancing problem was addressed in two ways. First, build enough generating capacity to meet peak-hour demand, plus a reasonable cushion to account for unexpected generator outages. Second, ensure an adequate fuel supply to opera te electrical generators month-after-month and year-after-year to meet customers’ energy de mand. This was sufficient because traditional resources provided system operators with the m eans to deal with the fundamental requirements of power system operation. Because of th e way the Northwest hydropower system was developed, over most of the past 40 years, th e Northwest's resource planning has been more straightforward: to meet the annual energy need s of the system. The Northwest was able to focus on annual energy needs because the hydrosys tem provided ample capacity and flexibility to balance generation and load at all times.

Today, power system operators and planners must again focus on ensuring that the installed generating capacity is flexible enough to rapidly increase or decrease output to maintain system
balance second-to-second and minute-to -minute. This shift is a result of the dramatic increase in the region’s use of wind generati on, which creates unique challenges for system operators. Over the course of minutes and hours, the output of a wind generator can be extremely variable, ranging from zero to its maximum output. While power system operators try to predict changes in wind generation, they also need other capacity , sufficiently flexible, to offset unexpected changes in its output.



## POWER SYSTEM REQUIREMENTS: CAPACITY, ENERGY,
AND FLEXIBILITY

Capacity: Meetin g Peak Demand

In previous plans, the Council focused primarily , like other regional resource planners, on the energy output of generators. Energy is the total ou tput of a plant, typically measured over a year in megawatt hours or average megawatts. The touchstone for judging whether the region hadChapter 12: Capacity and Flexib ility Resources Sixth Power Plan

12-3 adequate resources has long been whether the power system could generate sufficient energy during adverse water conditions. This focus wa s largely due to the Northwest’s hydrosystem, which had an excess of installed capacity. Because most traditional generating resources, like natural gas, coal, and nuclear pl ants, provide additional capacity at the same time they provide the ability to generate energy, most resource pl anning was carried out in an environment in which capacity could be taken for granted, as long as enough additional energy capability was provided to meet the total energy needs of the region.

Capacity is the maximum net output of a generator, measured in megawatts. For most generation, this is relatively straightforward: the plants can operate at their maximum output level (within certain pr edictable environmental, emission, a nd technical constraints) if called upon by the system operators, unless they have an unplanned, or forced, outage. Utilities account for the probability of forced outages by carrying contingency reserves, which are required by the North American Electric Reliability Corporation (NERC) and the Western Electricity Coordinating Council (WECC) reliability standards. The required contingency reserves equal about 6 percent to 8 per cent of demand for mo st utilities.

For hydroelectric generation, measuring capacity can be problematic. The total output of the hydrosystem is limited by its fuel supply, water, wh ich is extremely variable from year-to-year. It is also limited by the fact that the reservoi r system can only store about 30 percent of the annual runoff volume of water. Under some circumstances, there may not be enough stored water to run the generators at their maximum level to meet hourly load during peak conditions, like multi-day cold snaps in the winter or multi-day heat waves in the summer. While the machinery may be capable of reaching maximum out put for short periods, it cannot sustain that level of output for longer periods . In fact, the maximum output a hydroelectric facility can provide depends on the duration of the output pe riod--the longer the period, the lower the maximum sustainable output. This type of capacity is referred to as “sustainable capacity” and is a characteristic peculiar to hydroelectric systems.

The Northwest Resource Adequacy Forum, jointly chaired by the Council and Bonneville, with participation by other regional util ities and interest groups, has de voted considerable effort over the past several years to reaching an understa nding of the hydrosystem’s sustainable capacity value. The work of the forum is described more fully in Chapter 14.

Wind generation capacity also raises capacity issues because it is not controllable. Wind generation is variable; operators can reduce ge neration when the wind is blowing, but they cannot make it produce more, even if the rated wi nd capacity is much higher. Furthermore, the output level is relatively unpredicta ble and, in the Northwest, is un likely to be available at times of extreme peak load--for example when load is high because of a winter cold spell or a summer hot spell.

The amount of installed capacity expected to be available duri ng peak-load hours is often called a generator’s “peak contribution” or “reliable capacity.” There is a body of technical literature
on methods for the calculation of this value. Analysis done by Bonneville and the Resource Adequacy Forum suggests that, for the wind area at the east end of the Columbia River Gorge, where much of the region’s current wind generati on is located, there is an inverse relationship between wind generation and extreme temperatures , both in winter and summer. This is likely due to widespread high pressure zones covering the region’s load centers (the biggest ones beingChapter 12: Capacity and Flexib ility Resources Sixth Power Plan

12-4 west of the Cascades) and the area of wind generation east of the Cascades during periods of extreme low and extreme high temperatures. Fi gure 12-1 illustrates the loss of wind generation during a recent winter period. While efforts to better define the reliable capacity of wind generators are ongoing, both in th e Northwest and in NERC and WECC, the Resource Adequacy Forum has adopted a provisional peak contributi on for wind of 5 percent of installed capacity. This work will need to address the impact of future wind development in other areas, such as Montana and Wyoming, that may have different weather patterns and could improve the overall capacity contribution of wind.

Figure 12-1: Bonneville Wind Generation January 5 - 29, 2009

0 200 400 600 800 1000 1200 1400 1600 1800MW

Jan 14 Jan 27

The current adequacy assessment (Chapter 14 ) indicates that the Northwest will probably encounter a summer-capacity problem before a winter-capacity problem, largely because of hydrosystem constraints and different expectations about the availa bility of power from plants owned by the region’s independent power pr oducers and from wider Western markets. Providing capacity to meet peak demand is only one part of balancing generation and load. Resources added to provide energy and flexibility will also help the region meet its developing summer-capacity deficit.

Before system planners and operators began to em phasize flexibility as part of the solution to the balancing problem, it was possible to talk about pure peaking resources. Peaking units were resources added to the system primarily to m eet peak-hour demand, wit hout having to generate large amounts of energy over the co urse of the year. Peaking units have been characterized as low-fixed cost and high-operating cost resources. These cost characteristics correspond to their intended infrequent use as peaking plants. To a certain extent, this characterization originated with the historical practice of demoting aging, less -efficient baseload units to infrequent peaking duty. In recent decades, however, specialized units capable of delivering a broad array of ancillary services as well as peak capacity at reasonable efficiency--such as aeroderivative andChapter 12: Capacity and Flexib ility Resources Sixth Power Plan

12-5 intercooled gas turbines and gas- driven high-efficiency recipro cating engines--have appeared on the market. These units may have greater per-ki lowatt capital costs than combined-cycle plants.

Resources in this category include simple-c ycle gas turbine generators (both frame and aeroderivative), reciprocating en gines, capacity augmentation feat ures for combined-cycle gas turbines (including water or steam injection and fi red heat-recovery steam generators), and utility demand response programs. Today, aeroderivative combustion turbines, reciprocating engines, and even some types of demand response, are of ten considered first for their flexibility and second for their ability to help meet peak de mand. Demand response programs are described more fully in Chapter 5. These generating technol ogies are discussed later in this chapter and in Chapter 6.



## Energy: Meeting Average Demand

Energy is the total output of a plant, typically over a year. For most plants, the maximum energy is simply the capacity times the number of hours pe r year that the plant ru ns, excluding forced or planned (maintenance) outages. For most types of generation, the energy output of the plant is not limited; the plant can run at its maximum le vel as long as desired, subject to forced or planned outages, and occasionally fuel s upply and environmental constraints.

A fuller discussion of the regional portfolio results of the Council ’s analysis, as well as their implications for meeting capacity and energy requir ements of the system, is in Chapter 10 of the plan.



## Flexibility: Providing Within-hour Balance

The basic measures of a plant’s flexibility are: its ramp rate, measured in megawatts-per-minute or some other short period; its minimum generati on level; and its capacity. Minimum generation is most often defined by a combination of physical limits and economic limits, as when a plant’s efficiency drops off dramatically below a certain point. Power system operators need to set aside a certain amount of flexible generation just to fo llow load, which varies. More flexibility is required if there is a significant amount of wi nd or other variable generation on the system.

The Northwest’s hydroelectric generators are trem endously flexible resour ces. Physically, they have a wide operating range and very fast ramp ra tes. The inherent flexibility of the Northwest hydrosystem helps explain why flexibility has been taken for granted in previous Power Plans. This inherent flexibility is now partly limited by the challenges of salmon protection in Columbia and Snake rivers and the increasing amount of flexibility that is needed.



## POWER SYSTEM OPERATIONS

The electric power system is or ganized into balancing authorities 1 for the purpose of operating the system reliably. Each generator (or fraction of a generator in specific circumstances) and load is in one, and only one, ba lancing authority. There are 17 balancing authorities in the
Northwest Power Pool Area and 36 in the Western Interconnection.

1 Balancing authority is NERC terminology for the entity that is responsible for the actions. Balancing area is sometimes used for the portion of th e electrical system for which the ba lancing authority is responsible.Chapter 12: Capacity and Flexib ility Resources Sixth Power Plan

12-6 Each balancing authority is responsible for a nu mber of things, includin g continuously balancing load and resources, contributing to maintaini ng the frequency of the interconnection at its required level, monitoring and managing transmissi on power flow on the lines in its own area so they stay below system reliabil ity limits, maintaining system vo ltages within required limits, and dealing with generation or transmission outages as they occur. It does these things using what are called ancillary services, most of which are services provided by generation or, less commonly, demand response under the control of th e balancing authority. The potential to expand demand response for ancillary servic es is addressed further in Chapter 5.



## Ancillary Services

The NERC and WECC reliability standards, and prudent utility practice, require balancing authorities to hold operating reserves , first to maintain load and re source balance in case of an outage of a generator or transmissi on line, second to meet instanta neous variations in load, and in the case of wind generation, fluctu ations in resource output.

The portion of operating reserve he ld ready in case of an outage is called contingency reserve, specified by NERC and WECC standards. The por tion of operating reserv e meeting the second requirement is called regulating rese rve in the reliability standards. Additional reserves that are not explicitly required by NERC and WECC, but ar e prudent practice and a ssist in meeting the regulation requirement, are often called balancing reserves.



## Regulating and Balancing Reserves

Operators must balance load and resources and ke ep track of imports and exports, all while load is continuously changing.

Balancing authorities do this by operating in a basic time frame of one hour, every hour of the day. The basic test of success in this balancing is cal led area control error (ACE). ACE is a measurement, calculated every four seconds, of the imbalan ce between load and generation within a balancing area, taking in to account its previously planned imports and exports and the frequency of the interconnection. The NERC an d WECC reliability standards govern the amount of allowable deviation of the balancing author ity’s ACE over various in tervals, although the basic notion is that ACE should be approximate ly zero. The ACE is maintained through a combination of automatic and operator actions. The automatic part is done through a computercontrolled system called automatic generation control (AGC).

The basic regulation and balancing control challenge for the balanci ng authority is driven by load changes, both random, short-term fluctuations, and trends within the hour. It is exacerbated by the presence of large amounts of wind generation physically lo cated in the balancing area, whether or not that wind is generating for the cu stomers of the balancing area. There are specific exemptions from this requirement that in some cases require additional institutional or business practice changes, which are described later.

This is illustrated in several graphs based on five-minute interval data from the Bonneville balancing area in the first week of January 2008. The problems in this period are representative of the problems in other periods, although for Bo nneville the problems are now magnified by the increase in installed wind capacity on its system. Bonneville now has approximately 2,800Chapter 12: Capacity and Flexib ility Resources Sixth Power Plan

12-7 megawatts of installed wind capacity. Figure 12-2 illustrates a typical weekly load pattern at five-minute intervals, with a sharp daily ramp in the morning as people rise, turn on electric heat, turn on lights, take showers, and as businesses begin the day.

It also shows the Bonneville balancing area wind generation from the same period, illustrating the irregular pattern typical of wind generation. Th e data from this week will be used in several subsequent graphs, focusing on shorter time in tervals and illustrati ng particular issues.

Figure 12-2: Example Load and Wind Pattern BPA January 1-7, 2008, Midnight to Midnight

Focusing on a single day, January 7, 2008, Figure 12-3 highlights a single operating hour, from
6:00 a.m. to 7:00 a.m. 0 1000 2000 3000 4000 5000 6000 7000 8000 9000 10000

MW

Wind generation (1400 MW capacity) Load

0 1,000 2

, 000 3,000 4 000 5 000 6,000 7,000 8

, 000 9 000 10 000

M

Wind Generation (1,400 MW capacity) Loa

dChapter 12: Capacity and Flexib ility Resources Sixth Power Plan

12-8 Figure 12-3: Daily Load Curve - BPA January 7, 2008 Midnight to Midnight

5000 6000 7000 8000 9000 10000MW 7:00 a.m. 8766 MW

6:00 a.m. 8004 MW

5000 6000 7000 8000 9000 10000MW 7:00 a.m. 8766 MW

6:00 a.m. 8004 MW

A balancing authority has to deal with a load ramp of, for example, 762 megawatts over the course of an hour, using the gene ration under its control in its own balancing area. At the same time, it must deal with any imports or exports th at have their own time pattern for adjustment. Scheduling between balancing au thorities in WECC is generall y done in one-hour increments, with the schedules ramping in across the hour , from 10 minutes before the hour to 10 minutes
after the hour.

Figure 12-4 focuses on the 6:00 a.m. to 7:00 a.m. load from the previous graph, while adding a hypothetical net schedule (includi ng exports from and imports into the balancing area), and the generation scheduled to meet the average hourly load by any of its providers, including the transmission provider’s merchant arm. The ba lancing authority must address the differences (both positive and negative) betw een the total scheduled genera tion and the net load in the balancing area by operating the generation in its control either up or down to match the load instantaneously, and to manage its ACE to acceptabl e levels. The graph points to the differences between scheduled generation and actual load th at requires balancing authority action.Chapter 12: Capacity and Flexib ility Resources Sixth Power Plan

12-9 Figure 12-4: Example Hourly Scheduling

7600 7800 8000 8200 8400 8600 8800 9000

5

:50 6 : 0 0 6 : 1 0 6 : 20 6 :30 6 :40 6 : 5 0 7 : 0 0 7:10M W Balancing Authority action

7600 7800 8000 8200 8400 8600 8800 9000

5

:50 6 : 0 0 6 : 1 0 6 : 20 6 :30 6 :40 6 : 5 0 7 : 0 0 7:10M W Balancing Authority action

There are NERC and WECC reliability standards that govern how that action must be taken. In addition to contingency reserves, which must be av ailable in case of a sudden forced outage, the standards require regulation reserves, which is ge neration connected to th e balancing authority’s AGC system. The standards do not require a ny specific megawatt or percentage level of regulation reserves. Rather, they require that the balancing aut hority hold a sufficient amount so that its ACE can be controlled within the requir ed limits. How the balancing authority meets the requirements highlighted in Figure 12-4 i nvolves some discretion on its part.

Most balancing authorities prefer to break the requirement into two parts: one meeting the pure regulation requirement, allowing AGC generation to respond ev ery four seconds; the other adjusting generation output over a longer peri od, typically 10 minutes. The pure regulation requirement is illustrated by Figure 12-5, whic h shows a hypothetical, random pattern at foursecond intervals (which is the kind of pattern the load actually exhibits) on top of a five-minute trend. This is the load that the generation on AGC actually follows.Chapter 12: Capacity and Flexib ility Resources Sixth Power Plan

12-10 Figure 12-5: Example Load at Four -Second Intervals Over Five Minutes

Actual Load

Underlying short-term trend

Figure 12-6 illustrates one pattern of breaking that requirement up, separating the regulation requirement for generation on AGC from the re maining requirement, usually called loadfollowing or balancing. 2

Figure 12-6: Illustration of Hour ly Scheduling with Load Following

7600 7800 8000 8200 8400 8600 8800 9000

5

: 50 6: 0 0 6: 10 6:20 6: 3 0 6: 40 6: 5 0 7: 00 7 : 10MW Load following or balancing Regulation

7600 7800 8000 8200 8400 8600 8800 9000

5

: 50 6: 0 0 6: 10 6:20 6: 3 0 6: 40 6: 5 0 7: 00 7 : 10MW Load following or balancing Regulation

Balancing authorities plan for regulation and balanc ing services before the need for them arises. They ensure that enough scheduled generati on is on AGC to provide moment-to-moment regulation services. They also plan to operate some generators at levels lower than they otherwise would in order to have the ability to increase generation and provide incremental loadfollowing. Conversely, they may also need to operat e some generators at levels higher than they

2 When the only remaining requirement is the variation in load, load-following is the most common term. When the requirement includes the effect of variable generation, like wind, the term balancing is often used instead.Chapter 12: Capacity and Flexib ility Resources Sixth Power Plan

12-11 otherwise would in order to have the ability to decrease generation and provide decremental load following.

By operating generators in this manner, a balancing authority can incur increased operation costs, increased maintenance costs, and foregone revenues. These are the opportunity costs of providing regulation and load-following or balanci ng services. Balancing authorities typically decide which generators to use for regulat ion and load-following based on the physical characteristics of their generators and the opportunity cost of opera ting specific generators in this manner. Much of the region’ s flexibility, and pa rticularly for the large amount of wind generation in Bonneville’s balancing area, ha s been provided by the hydrosystem. This description focuses on issues raised for the No rthwest and its hydro system, but it needs to be recognized that there are other areas of the wo rld or the U.S., like Texas, where integrating significant amounts of wind has taken place using non-hydro resources. Texas, for instance, currently integrates approximately 8,000 megawatts of wind primarily with combined-cycle gas generation.

Historically, the cost of operating the power sy stem to provide regulation and load-following
services received little atte ntion. The effect of wind and other variable generation on the balancing authority’s ability to balance generation and load has raised awareness of the cost of providing these services. Improvi ng operating procedures and busine ss practices should help to hold down integration costs, but they will likely in crease over time as more variable generation is added to the system.



## FLEXIBILITY ISSUES RAISED BY WIND GENERATION

Unpredictable and rapid swings in the output of wind generators have increased the need for power system flexibility. Load is typically much more predic table in the one-to-two hour time frame than wind generation. If load is relative ly flat, and the wind unexpectedly drops off over the course of 10-20 minutes, then system operato rs must ramp up other generation at the same speed that the wind generation is ramping down in order to maintain load and resource balance and support the system frequency. Likewise, if the wind unexpectedly in creases, then system operators must be able to ramp down other gene rators in order to maintain load and resource
balance.

The possibilities become more complicated with changes in both wind generation and load over a given time period. But the result is still the need to be able to quickly adjust generation up or
down.

Figure 12-7 illustrates a situation where both load and wind generation increased at the same time. It shows the load and wind pattern from th e last day of Figure 12-1, and the effect of wind generation if its capacity were three times gr eater than what was operating on January 7, 2008, assuming for the sake of illustration that th e additional wind genera tion did not bring any geographical diversity with it. Note that Bonneville already has a bout 2,800 megawatts of installed wind capacity, instead of the then 1,400 megawatts. Bonneville is concerned about the potential of over 6,000 megawatts by 2013.Chapter 12: Capacity and Flexib ility Resources Sixth Power Plan

12-12 Figure 12-7: January 7, 2008 Load and Hypothetical Wind Data Midnight to Midnight

0 1000 2000 3000 4000 5000 6000 7000 8000 9000 10000MW Load Wind Wind * 3 Load ramp = 234 MW

Wind ramp = 1158 MW

Looking at the early morning hours only, between 3:00 a.m. and 4:00 a.m. indicated by the vertical bars on the graph, we see an increase in load of 234 megawatts in that period. We also see an increase in the hypothetical wind genera tion of 1,158 megawatts. System operators would need to ramp down other generators by 924 megawa tts to maintain system balance. Because Bonneville can face significant minimum generati on requirements in the low-load night time hours, this pattern is a particular problem for th em. Solutions to these issues, some of them under development already, are discu ssed in the following section.

For capacity and energy, it is po ssible to provide estimates of the timing and size of future deficits. At this time, we are unable to make a similar projection for flexibility. This is because the industry has not yet developed standard methodologies and metrics to make such an assessment. However, Bonneville has estimated in its recently concluded 2010 rate case that by the end of 2011 it might need to set aside up to about 750 megawatts of generation to respond to unexpected drops in wind generation, and about 975 megawatts of gene ration to respond to unexpected increases in wind generation. These amounts are based on a wind forecast of almost 3,845 megawatts of installed wind, a 30-minute pe rsistence forecast and several mitigation measures for wind generation outside the level of the set-aside bala ncing reserves. For Bonneville’s needs specifically, see also the discussion in Chapter 13.



## Response to Growing Need for Flexibility

The response needs to be twofold. First, m odify existing operating procedures and business practices to allow the maximum and most effici ent use of the region’s existing flexibility for those balancing authorities with large am ounts of wind generation. Second, the new dispatchable generation needed for energy, or to meet the peak-hour capacity needs of the system (should that become the primary need in the future ), should also be able to be adjusted up orChapter 12: Capacity and Flexib ility Resources Sixth Power Plan

12-13 down to deal with changes in wind output, and to allow the region’s balancing authorities to maintain their ACE measures within acceptable bounds.



### Institutional Changes
There are several changes in ope rating procedures and business practices that would either reduce the burden on the balancing areas or substa ntially increase the available flexibility of the existing system.

Increasing the accuracy of short-term wind fo recasting, either by wind generators or the balancing authorities themselves would reduce th e amount of balancing reserve capacity needed
to cover a forecast error. Bonne ville has estimated, for example, that using the prior 30 minutes’ generation level (rather than previous methods th at looked further back) as the forecast for the next hour would substantially reduce the forecas t error and the amount of needed balancing reserves. Bonneville has made this adjustment and adopted other methods to increase forecast accuracy. More sophisticated wind modeling is also being explored.

Going to a 10-minute scheduling window instead of the current whole-hour scheduling would also help maintain the host ba lancing authority’s ACE by allowing it to bring in generation from other balancing authorities. This would requir e a more developed market (either bilateral or centralized) in these intra-hour, short-term generation deliveries to take advantage of the new framework. The joint initiativ e between ColumbiaGrid, Northern Tier Transmission Group, and WestConnect is taking steps in this direction by creating a tool to facilitate within-hour
transactions on a bilateral basis.

Increasing the availability and eas e of use of dynamic scheduling is another important change. This mechanism enables generation in one balanc ing authority to be transferred into another balancing authority for the ACE calculations of the two areas. This is helpful for several reasons. It allows available gene ration in one balancing authority to be used in another to meet the latter’s regulation and balancing needs.

It also allows wind generation th at is physically located in one balancing authority, but meeting load in another balancing authority, to be eff ectively transferred out of its area and into the second authority’s area and ACE. Normally, while the FERC Open Access Transmission Tariff (OATT) allows the first balanci ng authority to charge some ot her party (the wind generators meeting external load or the external load) fo r the ancillary services , including regulation and balancing, NERC standards require that the ho st balancing authority provide the physical response. Dynamic scheduling allows both th e physical response and cost of the wind generation to be the responsib ility of the recipient load.

Dynamic scheduling is a long-established practice, but is typically done now on a case-by-case basis for relatively long periods, and it requi res time-consuming, individual coordination between balancing authorities. Work is underw ay by the joint initiativ e to standardize the protocols and communication to make dynamic sche duling easily and quickl y available--ideally so that dynamic schedules could be changed on an hour-to-hour or shorter basis.

There are some additional issues that need to be resolved rega rding the limits on the amount of generation that can be dynamically scheduled over various transmission paths, particularly if the schedule involves long distances; for example, dynamic scheduling between Bonneville and theChapter 12: Capacity and Flexib ility Resources Sixth Power Plan

12-14 California ISO. Among these issues is control of voltage levels in the system. Voltage levels on transmission lines are in part a function of the line loading, and dynamic scheduling tends to change line loadings rapidly, increasing the burden of controlling voltage levels within reliability limits. The Northern Tier Transmission Group a nd ColumbiaGrid have formed a group called the Wind Integration Study Team to examine these limits within the two entities.



### Adding Flexible Capacity
System planners and operators are looking at re sources that can be us ed to meet peak-hour demand and respond to variati ons in wind output. These fl exible-duty resources do not necessarily need to generate large amounts of energy over the course of the year. Resources typically placed in this categor y include: rapid-response natura l gas-fired generators; storage resources such as pumped-storage hydro plants; and utility demand response programs.

In the near term, natural gas-fired turbines and reciprocating engines app ear to be good options for meeting the increased demand for flexibility. To offset un expected changes in wind output, these resources need rapid-start capability and ef ficient operation at outpu t levels less than full capacity.

The LM6000 Sprint (50-megawatt) and LMS100 (100- megawatt) aeroderivativ e turbines are two good candidates for flexibility augmentation. Starting cold, both turbines can be ramped to their maximum output within 10 minutes. These aerod erivative turbines are more efficient than comparable frame turbines, and therefore more cost -effective to operate at partial output levels. The LM6000 Sprint is a commercially mature tec hnology with more than 200 units in operation. The first LMS100 unit went into commercial operat ion at the Groton Genera ting Station in South
Dakota in 2006.

Gas-fired reciprocating engines are also a good flexibility opti on. The Plains End Generating Facility in Colorado is a 20-unit plant that has an output range of anywhere from 3 megawatts to 113 megawatts. The engines have a 10-minute quick start capability a nd can ramp up and down in response to an AGC signal. All of the above options can be constructe d with short lead times, and therefore are good near-term fl exibility options. A more co mplete description of these natural gas-fired generating technologies is provided in Chapter 6.

Pumped-storage hydro is a good mid-term option for meeting increased demand for flexibility since it can quickly change its op erating level. These hydro plants operate in either a pumping mode or a generating mode. Traditional operation of pumped-storage hydro is based on the price of electric power. When the price of electric po wer is low, water is pumped from a source to a storage reservoir located at a hi gher elevation. When the price of electric power is high, the stored water is released and passed thr ough a turbine to generate power.

As more wind power is added to the system, pumped-storage opera tion is likely to respond to the price of regulation and load-fo llowing services. For example, operators of pumped-storage plants can commit in advance to increase pumpi ng when there are unexpected increases in wind output. Plants with variable-speed pumps are likely to be more responsive in these circumstances. Likewise, operators can also commit to increase gene ration when wind power output unexpectedly drops. Furthermore, operating th e plant in this manner is not likely to result in dramatic operating cost increas es or reduced revenue. Howeve r, with a 13-year constructionChapter 12: Capacity and Flexib ility Resources Sixth Power Plan

12-15 lead time, and high capital cost, risk is high. Other options ma y capture a large share of the ancillary services market before a new pump ed-storage plant can be brought on-line.

The potential use of hot water heaters, plug- in hybrid vehicles, and other demand response options to provide regulation and load-following services is desc ribed in Chapter 5, Appendix H, and Appendix K.Sixth Northwest Conservation and Electric Power Plan 

# Chapter 13: Bonneville’s Obligations

Summary of Key Findings........................................................................................................ ...... 1 Statutory Background ........................................................................................................... .......... 2 Bonneville’s Evolving Role..................................................................................................... ....... 3
The Council’s Recommendations for Bonnev ille’s Future Role in Power Supply .................... 3 The Regional Dialogue .......................................................................................................... ..... 5 Bonneville’s Posture Today; its Response to Regional Recommendations ............................... 6 The Administrator’s Resource Requirements................................................................................. 7
Conservation Resources......................................................................................................... ..... 8
Additional Resources........................................................................................................... ..... 10 Preliminary Conclusions Regarding B onneville’s Draft Resource Program............................ 13 Major Resources ................................................................................................................ ....... 14 Assessing Fish and Wildlife Costs and Acco modating Fish and Wildlife Operations................. 14



## SUMMARY OF KEY FINDINGS

Bonneville engaged in an extens ive, multi-year set of regional processes, culminating in the Regional Dialogue in 2007 and power-sales contract s in 2008, to define its future power supply role. The Council strongly supported and participat ed in these processes and offered a number of recommendations as part of the Fifth Power Plan, which were addressed in the Regional Dialogue.

Bonneville adopted a Regional Dialogue Policy, wh ich defined its potential resource-acquisition obligations for power sales after 2011, whether at Tier 1 or Tier 2 rates. The administrator’s potential future obligations also include addi tional firm energy, capacity, and flexibility for integrating wind power into Bonnev ille’s balancing area. Its obliga tions to provide flexibility for wind-power balancing also are driven by its obligations under NERC standards as the host balancing authority for wind-power resources that are meeting load elsewhere, primarily in
California.

The Council’s analysis, while it looks at re gional capacity and energy requirements, does not break out utility-specific capacity and energy re quirements and does not look at within-hour issues like flexibility. Thus there might be spec ific Bonneville obligations that are not addressed
in detail in the Sixth Power Plan. The size of these obligations for Bonne ville is, however, not
well known at this time because it will be driven by choices of Bonneville’s customers and the amount of wind power that is located in Bonneville’s balanc ing area whether to serve its customers, other regional utilities, or for sale outside of the region. These will not be known until after the adoption of the plan. Moreover, th e supply of resources available to meet these obligations, particularly for add itional flexibility to deal with wind integration, is uncertain at this time. There are, for instance, a number of regional and West-wide discussions underway about institutional and business pr actice changes to help balanci ng authorities deal with these
issues.

Because of these uncertainties, the Council has se veral general principles to guide Bonneville should it need to acquire resources to meet any of these several ki nds of obligations. They are, briefly:Chapter 13: Bonneville’s Obligations Sixth Power Plan

13-2 • Aggressively pursue the Counc il’s conservation goals first

• Aggressively pursue the various institutional and business-practice changes to reduce the demand for flexibility and to use the existing system more fully

• Look broadly at the cost-effectiv eness and reliability of possi ble sources of new capacity and flexibility, such as gas or other generati on types, and take into account synergies in meeting several types of needs with single resources



## STATUTORY BACKGROUND

The Northwest Power Act gave the Bonneville Power Administration ne w authorities and new responsibilities. It authorized the Bonneville administrator to acquire resources to meet the administrator’s obligations. At the same time, it obligated the agency to serve the loads placed on the agency by preference customers and the inve stor-owned utilities (IOUs). The Act also authorized sales to federal agency customers and to the direct-service indust ries (DSIs). Sales to the DSIs must provide a portion of the reserves available for meeting the administrator load obligations.

The Act also gave new authority to the member states of the Pacific No rthwest Electric Power and Conservation Planning Council (Council), the interstate compact authorized by the Act. Congress directed the members of the Council, ap pointed by the governors of the member states, to develop a 20-year regional power plan. One component of that plan is the Council’s fish and wildlife program, intended to protect, mitigate, and enhance fish and wildlife, and related spawning grounds and habitat, that have been affected by the constr uction and operation of hydropower dams in the Columbia Ri ver Basin. The Council’s power plan is meant to assure the Pacific Northwest of an adequate, efficient, ec onomical, and reliable power supply. Bonneville, with certain narrow exceptions, must act consistently with th e power plan in its resourceacquisition activities. This consistency requirement is most prominent when Bonneville proposes to undertake a number of actions related to a major resour ce, that is, a resource that has a planned capability greater than 50 average megawa tts and is acquired for a period of more than five years. Thus, Congress intended the four Nort hwest states to have some say in Bonneville’s resource-acquisition activity.

Bonneville occupies a unique, dual role in the re gion’s utility system. On one hand it functions as a utility business, supplying energy, load-f ollowing, reserves, and transmission. Indeed, the agency markets the output of the federal base system (FBS), which consists of 31 federal hydroelectric projects (29 in the Columbia River Basin and two outside the basin), one nonfederal nuclear plant, and seve ral other small non-federal power plants. As noted, Bonneville also acquires resources to meet customer load s. In acquiring resources, the Act directs
Bonneville to make cost-effective conservation the resource of first choice. To carry out that function, Bonneville also manages programs that help utilities acquire conservation. Bonneville accounts for the amount of conservation acquired and verifies savings. These functions are important in assuring the regi on that ratepayer funds are be ing expended in a business-like fashion. To enhance the range of conservation re sources that will be available in the future, Bonneville also funds research and development. The resource of second choice under the Act is
renewables. Bonneville both ac quires renewables, as it has a dded about 245 megawatts of wind power to its portfolio of resour ces, and provides integration serv ices, both for its own renewableChapter 13: Bonneville’s Obligations Sixth Power Plan

13-3 resources and for wind located in its control area but owned by others. In acquiring renewable resources, Bonneville first adds to its power supply to meet its total contractual load obligation and secondarily assists its customers who are obl igated to meet renewable portfolio standards (RPS) set by their respective st ates. Again, Bonneville also s upports research and development in the realm of renewable resources, to expand th e amounts and sorts of rene wables that will be
available in the future.

On the other hand, in addition to its utility bus iness functions, Bonneville is also a federal agency, to which Congress entrusted defined public purposes. The Act gave Bonneville the responsibility of funding efforts to restore fish and wildlife aff ected by the hydroelectric dams on
the mainstem Columbia River and its tributarie s. Among other public purposes, the agency also funds low-income weatherization programs through local public utilities, at the administrator’s
discretion.



## BONNEVILLE’S EVOLVING ROLE

Bonneville’s evolving role in the changing electricity utility indus try has been the subject of a number of public processes that have garner ed widespread regional participation. These processes ultimately were reflected in recommenda tions from the Council in its Fifth Power Plan and decisions by Bonneville in it s Regional Dialogue Policy.

The Comprehensive Review of the Northwes t Energy System in 1996, the 1997 Cost Review, the Joint Customer Proposal in 2004, and the ad ministrator’s 2005 Power Supply Role for fiscal years 2007-2011 all examined the issue of Bonneville’s role in the region’s electricity system. Each step in this series of discussions contributed to or m odified in some way the region’s thinking about what role Bonneville should serve. Naturally, not every entity that took part in each process endorsed every recommendation.

Impetus for these various processes derived fr om the restructuring a nd deregulation of the nation’s electricity industry following passage of the National Energy Policy Act of 1992. Bonneville, the marketer of nearly half the electricity consumed in the region, faced an unusual and troubling situation. The agen cy’s longstanding customers suddenly sought to diversify their wholesale power sources away from Bonneville by purchasing from competitive, lower-cost providers of electricity. In the mid-1990s, ther e were concerns that Bonneville’s high fixed costs, including the debt on the Federal Columb ia River Power System (FCRPS) and its past investments in nuclear power plants, would make it uncompetitive in the wholesale power market. Against this background, the region dete rmined it was time to give serious thought to
Bonneville’s role in the re gion’s electricity system.



## The Council’s Recommendations for Bonneville’s Future Role in Power Supply

The Council recognized that recommendations fr om these various regional processes had a number of principles in common. Three were particularly impor tant. The first was preserving the region’s low-cost hydroelectric resources through long-term contracts. Second was improving preference customer utilities’ and fede ral agencies’ incentives to meet their load growth with responsible resource choices by charging an individual utility that chooses to have Bonneville meet its needs beyond the capability of the existing FCRPS the cost of incrementalChapter 13: Bonneville’s Obligations Sixth Power Plan

13-4 supplies. The third was providing equitable and pr edictable benefits to the residential and smallfarm customers of the region’ s investor-owned utilities.

Based on these considerations, the Council devel oped its own set of recommendations regarding Bonneville’s future role in power supply for the Fifth Power Plan. As summarized here, these
remain the Council’s recommendations regarding Bonne ville’s role:

• Bonneville should market the output of the exis ting FCRPS to eligible customers at cost. Customers that request more power than Bonne ville can provide from the existing federal system should pay the additional cost of provi ding that service. This change in role should be implemented through 20-year contra cts that should be offered as soon as possible, and compatible rate structures.

• Bonneville should develop a clear and durable policy regarding the agency’s future role in resource acquisition, to guide contract negotiations and future rate cases.

• To implement its new role, Bonneville shoul d allocate the power from the existing FBS among eligible customers through a process that minimizes opportunities for gaming the

process.

• Bonneville should move to implement tiered ra tes as soon as practicable; if they cannot be offered in new contracts by October 2007, the Council would consider recommending their implementation under the existing contracts.

• Bonneville should offer the full range of products currently available, such as requirements, block, and slice products. The costs of each product should be confined to the purchasers of that product, avoiding cross-subsidies.

• If Bonneville offers service to the DSIs, th e amount of power and term should be limited, the cost impact on other customers should be minimized, and Bonneville should have the right to interrupt service to maintain syst em stability and cover any temporary power supply inadequacy.

• Bonneville should find a stable and equitable approach to offer benefits of low-cost federal power to the residential and small-fa rm customers of the IOUs for a significant period.

• Bonneville and the region’s utilities shoul d continue to acquire the cost-effective
conservation and renewable resources identi fied in the Council’s power plans.
Bonneville’s role could be reduced to the ex tent customers can meet these objectives. But, if necessary, Bonneville must use the full extent of its authorities to ensure that the
cost-effective conservation and renewables id entified in the Council’s power plan are
achieved on all its customers’ loads. The Council committed to working with Bonneville, utilities, the stat es, regulatory commissions, and other regional and Westwide organizations to ensure that appropriate adequacy policies are in place and that the data and other tools to implement the policies are available.

• Bonneville should continue to carry out its fish and wildlife obligations, allocating its mitigation costs to the existing FCRPS.Chapter 13: Bonneville’s Obligations Sixth Power Plan

13-5 

## The Regional Dialogue

The concepts that emerged from the Comprehens ive Review and the Joint Customer Proposal, as well as the Fifth Power Plan, have been addres sed in subsequent discussions among Bonneville, its customers, state agencies, regulatory bodies, the Council, and public interest groups in a process called the “Regional Dialogue.” The Regi onal Dialogue concluded in 2007 with a set of policy decisions by Bonneville to guide develo pment of tiered rates and new power-sales contracts to replace the contract s that expire in 2011. The hi ghlights of the Regional Dialogue Policy, as expressed when the policy was adopted, follow.

• Bonneville will offer contracts to all its custom ers, public utilities, IOUs, and DSIs; at the same time. For public utilities, Bonnev ille will develop ne w 20-year contracts accompanied by a long-term Tiered Rate Methodology (TRM). Through the contracts and TRM, each public utility will get a Hi gh-Water Mark (HWM) that defines the
amount of a customer’s load that can be serv ed with Federal power at BPA’s lowest costbased Tier 1 rate. To meet load abov e the HWM customers can choose to purchase power from either non-federal resources or from Bonneville at rates reflecting Bonneville’s marginal cost of acquiring the additional power, or through a mix of Bonneville Tier 2 priced power and non-federal resources.

• Bonneville will acquire resources, if necessar y, to supply up to 250 megawatts at the Tier 1 rate to new public utilities (including ne w and existing public body tribal utilities).

• Bonneville will acquire resources to augmen t the existing system by the lesser of 300 megawatts or the amount needed to meet utilities’ HWMs based on their Fiscal Year 2010 loads. At the 300-megawatt cap, this woul d be roughly a 4-percent increment to the existing system and is in addition to any acquisitions to serve new public utilities.

• Bonneville will offer three produc t choices: load-following, block, and slice. The loadfollowing product will include services to follo w the actual loads a customer experiences. Slice and block products do not in clude load-following service.

• Bonneville will increase the amount of power sold under the slice product from the current 22.6 percent to as much as 25 per cent of the power available from the FBS

resources.

• Bonneville acknowledged that service to the DSIs had not been resolved and so that issue was not decided in this policy.

• Bonneville omitted a section on the residentia l exchange, due to then-recent decisions from the Ninth Circuit. Nonetheless, Bonnev ille’s goal is to ensure that the residential
and small-farm customers of the IOUs receive a fair and reasonably stable share of the benefits from the federal system over the long term, consistent with law, that will parallel the certainty obtained by public utilities.

• Bonneville will institute a regional cost review to give customers and other stakeholders opportunities to comment on Bonneville’s costs.Chapter 13: Bonneville’s Obligations Sixth Power Plan

13-6 • Bonneville established guidelines for dispute resolution, in response to customer requests,
but noted that final decisions in this aren a likely will be taken in conjunction with development of the TRM and power sales contracts.

• Bonneville will pursue the development of all cost-effective conservation in the service territories of public u tilities served by Bonneville and of renewable resources based on its share of regional load growth. Bonneville expe cts these goals to be met to a significant extent through programs initiated and funded by its public utility customers. Bonneville will supplement and facilitate utility initiatives. Bonnev ille will provide the necessary integration services to customers that wish to acquire non-federal renewable resources to meet their load growth and enhanced incentives for conservation development.

• Bonneville will require its customers to provide their load and resource data and resource development plans necessary to track regiona l implementation of the voluntary resource adequacy standards adopted by the Council. Bonneville did not make compliance with the standards a contractual requirement.

• Bonneville will propose stable and predictabl e low density discount (LDD) and irrigation rate mitigation (IRM) programs in future rate proceedings. Bonneville will ensure that the LDD approach will not bias customers’ c hoices between taking power at a Tier 2 rate
from Bonneville or from non-federal resources.

These policy choices did not conclude the Region al Dialogue process. Negotiation and drafting of new contracts, their release for public comm ent, and eventual execution were to follow.
Bonneville also committed to a review of its Nort hwest Power Act sections 5(b)/9(c) policy. The TRM was to be developed in a se parate Northwest Power Act Secti on 7(i) process, as were rates to be effective for power sales under the Regiona l Dialogue contracts in Fiscal Year 2012. The Regional Dialogue policy decisions were meant to inform those subsequent processes, but it did
not decide them.



## Bonneville’s Posture Today; it s Response to Regional Recommendations

Late last year Bonneville signed 20- year contracts with all its public utility customers. This was the culmination of a lengthy public process in whic h all parties had the oppor tunity to address the
terms and conditions under which Bonneville would o ffer power to its customers. The fact that these contracts are long-term should help ensu re the stability of th e relationship between Bonneville and its customers. Knowing that Bonne ville will have this long- term, stable financial relationship with its customers s hould also bolster confidence th at Bonneville will be able to meet its annual payment to the U.S. Treas ury. The contracts al so support Bonneville’s commitment to conservation and renewables, as well as to meeting its fish and wildlife costs.

Bonneville has also developed and is prepar ing to implement a Tiered Rate Methodology. Bonneville will sell electricity from the existing FCRPS to eligible customers at cost. To ensure
that it has sufficient resources to meet the initial demand, Bonnev ille will augment the federal base by acquiring a limited amount of additional res ources, the cost of which it will meld with the cost of the existing system. This initial demand will be sold at priority firm (PF) Tier 1 rates. Customers that place more demand on Bonneville, that is, load above th eir individual high-waterChapter 13: Bonneville’s Obligations Sixth Power Plan

13-7 mark, will pay PF Tier 2 rates for that service, which will recover the costs of additional power
needed to meet this demand. Note that Bonneville has reached an accommodation with a
number of small customers that do not view themse lves as well-situated to acquire new resources on their own. Participants in this Shared Rate Plan will not face Tier 2 rates for individual growth, but if Bonneville has to acquire resource s to meet the overall growth of the pool, costs will be shared among all participants in this subset of customers.

This tiered rate structure s hould meet several goals in th e recommendations the region has offered. First, tiered rates will make clear w ho has responsibility for resource development. This structure should result in customers seeing the true cost of adding resources, which will provide better incentives for resource choices. It will also prevent the dilution of the value of the existing federal system that results from melding the costs of new and more expe nsive resources.

Bonneville also has responded to direction from the Ninth Circuit and reworked its Residential Exchange Program (REP). To accomplish this , the agency revised and implemented a new average-system-cost methodology, the result of a lengthy and comprehensive consultation process with customers, interested parties, and the Council. Bonneville ai med at sharing with the
residential and small farm customers of the IOUs the benefits of the generally lower cost FCRPS, both over the time when payments were made under settlements struck down by the Ninth Circuit, the look-back period, a nd going forward. The issues ar e again being litigated, and the customers are now discussing a nego tiated settlement to try to reso lve the uncertainty in the REP methodology under the Act.

These changes in Bonneville’s future role do no t change Bonneville’s fundamental responsibility to serve the loads of qualifying customers that choose to place load on Bonneville; it does not change Bonneville’s responsibility for ensuring the acquisition of Bonneville’s share of all costeffective conservation and renewable resources identified in the Council’ s plan; and it does not change Bonneville’s responsibility to fulfill its fish and wildlife obligations under the Act and the Council’s fish and wildlife program. It doe s represent a change in the way Bonneville traditionally has carried out those responsibilities.

Some important policies Bonneville has adopted to implement the recommendations of these public processes and the Regional Dialogue Policy have recently been ch allenged in the Ninth
Circuit. As of the date of the release of this draft plan, more than 40 petitions have been filed
that could result in the invalida tion of how Bonneville has responded to earlier judicial decisions directing the agency to implement the REP in lin e with the directives of the Northwest Power Act, its determination of how to make the pr eference customers whole, and its adoption and implementation of the tiered rates concept. De pending on the outcome of these challenges, the region may need to undertake a variety of effo rts to enable Bonneville to serve the roles identified in the long series of public proce sses outlined above and in the Regional Dialogue Policy.



## THE ADMINISTRATOR’S RESOURCE REQUIREMENTS

The Northwest Power Act requires that the C ouncil’s power plan “sha ll set forth a general scheme for implementing conservation measures and developing resources pursuant to section 6
of this Act to reduce or meet the Administrator’s obligations.” The Act requires the plan to give “priority to resources which the Council determines to be cost-effective,” and also ranks types ofChapter 13: Bonneville’s Obligations Sixth Power Plan

13-8 resources by priority: “Priority shall be given: first, to conservation; second, to renewable resources; third, to generating re sources utilizing waste heat or ge nerating resources of high fuelconversion efficiency; and four th, to all other resources.”

When Bonneville acquires resources, the Power Act then requires that, with certain narrow exceptions, all of Bonneville’s resource actions be consistent with the Council’s power plan. The Council engages in an extended planning process for developing and amending the power plan. It gathers experts in advi sory committees on important subjec ts the plan treats: generating resources, conservation, and natural gas, for several examples. These committees both contribute technical information for use in the pl an and evaluate analysis done by Council staff
and others. It is the staff’s an alysis and synthesis, combined w ith public input and comment, that
form the basis for the Council members’ decisions wh en they adopt a plan or a plan amendment. Bonneville participates in the Council’s process, sometimes as a member of an advisory committee, sometimes as a contributor to studie s or analyses, and sometimes as a commenter on draft Council positions. Being fu lly apprised of the thinking that underlies a final Council plan
should enable Bonneville to ensure that its ow n resource assessments and acquisitions build on the Council’s planning process and are consistent with the plan.

The Council’s power plan is first developed from a regional perspective. Much of the technical analysis for the plan assumes that the electric al loads in the region are served by all of the electric generation and conservati on resources available in the regi on, without respect to specific utility loads and resources. Th e result is a regional resource strategy that minimizes costs and risks as if the entire region we re served by all the resources a nd transmission in the region. The Power Act also requires, however, that the Counc il’s power plan specifica lly include a resource plan for Bonneville to act consiste nt with as it works to meet its current and future obligations. For this plan, the Council has examined Bonnevill e’s particular power system needs as described in this chapter. The Council did not develop it s own quantitative forecast of Bonneville’s loads and resources, concluding that analyses by Bonne ville of its projected loads and resources will
be more than sufficient for the Council to re ly on here for planning purposes, with an understanding of further work to come as describe d below. The Council has distilled the plan’s regional resource stra tegies into a set of resource-acquisi tion strategies specifically related to Bonneville and described in this chapter.

The Council expects Bonneville to acquire resources consistent with the power plan. Bonneville recently released a Draft Resource Program, intende d when final to guide the agency’s resourceacquisition choices for the next 10 years. As noted below, the Draft Resource Program describes Bonneville’s expected loads and resources in much finer detail than is possible in this plan, yet appears to be appropriately based in the power planning efforts of the Council and reflects the resource strategies in this pl an. The Council expects Bonnevill e’s final Resource Program to do
the same.



## Conservation Resources

Section 6(a)(1) of the Northwest Power Act oblig ates Bonneville to “acq uire such resources through conservation . . . as the Administrator de termines are consistent with the [Council’s power] plan.” And as noted, the Act further requires the Council to give first priority in the plan to cost-effective conservation resources. The powe r plan’s conservation measures thus have real legal meaning for Bonneville and real effects on Bonneville’s utility customers in terms ofChapter 13: Bonneville’s Obligations Sixth Power Plan

13-9 conservation’s ability to reduce the need for Bonne ville or the utilities to acquire lower-priority or higher-cost resources and in terms of the co sts of conservation acquired by Bonneville and its

customers.

The acquisition of cost-effective conservation by Bonneville through an ongoing program is not
conditioned in the Power Act on whether Bonneville is or soon will be out of load-resource
balance and therefore in need of additional resources. Rather, the point of this provision and of
the structure of the Power Act as a whole is that conservation is a resour ce used to serve firm power loads by reducing consumer demand for elect ricity. As such, conservation lessens the need for Bonneville to acquire power generate d by conventional generati ng resources that are more expensive than the costs of the hydrosys tem. The Regional Dialogue’s new power supply paradigm for Bonneville does not alter the legal or practical framework for Bonneville’s ongoing conservation program. Bonnevill e’s customers are still placi ng load on the agency and Bonneville is planning to acquire resources to serve its contractual load obligations, including potential loads above customer high-water marks a nd possibly direct-service industrial loads. Bonneville thus will need to continue to acquire cost-effective conservation to reduce loads and stretch the Federal Base System, consistent w ith the conservation provisions of this plan.

For this reason, the principal recommendation regardi ng Bonneville in the Sixth Plan, as in past plans, is that Bonneville aggressively pursue its share of the Council’s regional conservation goals. This is to ensure that Bonneville meet what ever load it faces, whether served at Tier 1 or Tier 2 rates, efficiently and as cost-effectively as possible.

Bonneville and its customers understand the basi c principle and through their actions have sustained the conservation program for decades. However, they have expressed concerns about the particulars here, that is, about the greater number of c onservation measures, about the expanded conservation goals, and about what mech anisms might ensure that Bonneville achieves its share of the regional conservation goals. Ev en as concerns over the near-term targets are being worked out in collaborative discussions, the utility customers have remained generally concerned about having goals, methods, measures, and costs imposed on them by Bonneville to satisfy the plan. Under Bonneville’s new resour ce policy, utility customers are responsible for the marginal costs of new resources acquired to meet their load growth, whether acquired by
themselves or from Bonneville at Tier 2 rates. Fo r this reason, the utilities believe it is in their interest to implement conservati on programs tailored to their part icular needs, programs that can serve to satisfy the plan’s conservation goals , without mandates from Bonneville and with
measures and costs the utilities themselves control.

In response, the Council believes Bonneville has th e discretion to tailor its conservation program to match this new power supply paradigm and to assuage the utility cust omers’ concerns, in a way consistent with the principl es the Council re cently outlined:

1. Conservation targets. Bonneville should c ontinue to commit that its public utility
customers will meet Bonneville’s share of the Council’s conservation targets. Bonneville should ensure that public utilities have the incentives and the support to pursue sustained conservation development. Active utility co mmitment to conservation should continue to
be a condition for access to Bonnevi lle power at Tier 1 rates.Chapter 13: Bonneville’s Obligations Sixth Power Plan

13-10 2. Utility reporting. Bonneville has included in its power sales contracts requirements for utility reporting and verification of conser vation savings so that Bonneville and the
Council can track whether conserva tion targets are being achieved.

3. Implementation mechanism. Bonneville should offer flexible and workable programs to assist utilities in meeting conservatio n goals, including a backstop plan, should Bonneville and utility programs be found insufficient.

4. Regional conservation programs. Bonneville sh ould continue to be active in funding and implementing conservation programs and activitie s that are inherently regional in scope,
such as NEEA.

It should be emphasized that the Council’s conservation methodology calculates conservation potentials for certain measures that might, at so me point, be covered by building or energy codes, and then assumes that the savings will be accomplished over time by either utility programs or
codes. The utilities should include these cost-e ffective, available conservation measures in their own plans and programs. However, if codes are adopted that ensure the capture of the potential savings, then the utilities may c ount the resulting savings in thei r service territori es against the regional target. The C ouncil in return expects the utilities to join with the Council, the governor’s offices, and other relevant state and lo cal agencies in their s upport of the necessary state and national improvements in codes and standards.



## Additional Resources

Along with the conservation program, the power pl an is to set forth a general scheme for developing other resources if needed to meet the administrator’s oblig ations. Bonneville may
need additional resources for a number of reas ons. These include Bonneville’s proposal to acquire resources to augment the existing system to serve the “high-water mark” load of its preference customers at Tier 1 ra tes; additional energy resources if needed because one or more customers call on Bonneville to meet their load grow th, at Tier 2 rates refl ecting the costs of the additional resources; additional resources to serve DSI loads, if Bonneville decides to offer such service; additional resources that may be neces sary for capacity and within-hour flexibility purposes, such as to support the integration of intermittent renewable resources like wind; additional resources as may be necessary fo r system reserves, system reliability, and transmission support; and additional resources if n ecessary to assist the administrator in meeting Bonneville’s fish and wildlife obligations under Section 4(h) of the Northwest Power Act. Conservation resources will help reduce the need for additional resources but are unlikely to
address all of these needs. Th e Council is not undertaking at th is time a detailed, quantitative
assessment of Bonneville’s need for additiona l resources, given the extent to which the overarching decisions and information that will affect this assessment are uncertain or in development. Instead, the Council is setting forth further information and a set of principles in this section (and linked to other chapters in the plan) to help guide any decisions by Bonneville to acquire additional resources consistent with the plan and the provisions of the Power Act:

Bonneville anticipates acquiring re sources on a long-term basis to meet its obligations under the new Regional Dialogue power sale s contracts. In the Long-Te rm Regional Dialogue Final Policy, Bonneville said it would acquire up to 300 average megawatts of power to augment the existing system to meet the “high-water mark” load of its preference customers at Tier 1 rates.Chapter 13: Bonneville’s Obligations Sixth Power Plan

13-11 In addition to augmenting energy to meet pr eference customer high-water-mark demand, the Regional Dialogue Policy also provides that over the 20-year contract period, Bonneville may augment its energy supplies by up to 250 average mega watts of power to be sold at the Tier 1 rate to serve any newly created public utilities. Additional high-water ma rks for new publics will be limited to 50 average megawatts in each rate pe riod, that is, in any tw o year period. Of the 250 average megawatts, Bonneville has designated 40 average megawatts for service, on a firstcome, first-served basis, at Tier 1 rates for r ecently created or future tribal utilities that experience load growth beyond their high-wate r marks. Bonneville also committed to augmenting its energy supplies by up to 70 averag e megawatts to meet possible expansions of the Department of Energy’s Richland facilities.

Beyond the Regional Dialogue provision to au gment energy supplies by up to 620 average megawatts to be sold at Tier-1 rates, as desc ribed above, Bonneville may also be required to acquire resources to meet loads that are beyond a customer’s high-water mark if the customer calls on Bonneville to meet its load growth. Th e amount of power sold to supply a customer’s above-high-water-mark load will be subject to a Tier 2 rate. This service is by definition flat, so if Bonneville acquires resources to meet these loads, it will offer pow er in flat blocks. Further,
Bonneville’s service to direct-s ervice industrial (DS I) customers has not been determined and could require additional resource acquisitions in the future. As of the time of this draft,
Bonneville and the DSI customers have not reach ed an agreement regarding service of those
industries.

Historically, Bonneville has purchased resources to serve the average annual energy needs of its
customers. Given the reductions in the ab ility of the hydropower system to support the integration of intermittent resources like wind, it is more likely that Bonneville will focus on acquiring resources that offer both added capacit y and flexibility that cannot be provided by conservation. Bonneville is designing such prod ucts in its Resource Support Services (RSS). For example, if a customer decides to meet its own load growth with new resources that have little or no firm capacity and ope rate intermittently, B onneville will not require that utility to
convert such resources into resources that can be used to meet firm loads by acquiring capacity, firming up the energy, and reshaping the output. Instead, Bonneville will do this for the customer and charge a resource-shaping charge, one of the RSS. Becau se many of Bonneville’s customers are acquiring wind to meet state-impo sed Renewable Portfolio Standards, this may prove to be an important Bonneville service.

Bonneville also will acquire resources to offer an cillary services to its utility and transmission
service customers. These are flexibility services such as regulation, load-following and balancing services, spinning rese rves, non-spinning reserves, suppl emental reserves, and voltage control. Bonneville will need to provide some of these services to support resources, such as a good portion of the wind generation physically located in Bonneville’s bala ncing authority area, that serve load outside the agency’s balancing ar ea. Resources needed for this service will be chiefly those that offer added capacity and flexibi lity. The resource strategy laid out in this plan acknowledges Bonneville’s potential need to acquire capacity res ources to meet heavy-load-hour demand and provide the flexibility needed to integrate intermittent resources.

Bonneville recently completed its 2009 Draft Res ource Program, designed to assess its potential resource needs as of 2013 and 2019. Significant uncer tainties remain at this time, though some will be resolved by the time of the final Sixth Pl an. Bonneville’s customers will have made theirChapter 13: Bonneville’s Obligations Sixth Power Plan

13-12 resource choices for at least the 2012-2014 period by November 1, 2009, which will have established the amount of Bonneville’s requirem ent for this period to serve above-high-watermark load. The other uncertainties describe d above (e.g., augmentation for new public loads)
will not have been resolved at this time. In its Draft Resource Program, Bonneville looked at the effect of all of the potential above-high-wa ter-mark loads being placed on the agency.

The effect of potential RSS requirements would be no bigger than the effect of the potential above-high-water-mark loads themselves, so th e potential effect of RSS on Bonneville requirements is covered by Bonnevi lle’s discussion of the potentia l effect of above-high-watermark load placement in the Draft Resource Program.

Not only will the magnitudes of some of the re quirements be unknown, but the availabilities of potential solutions, are, in some cases, not known either, because they will depend on ongoing regional and West-wide efforts. This is the case for solutions to th e balancing problems Bonneville faces in integrating the large amounts of wind generation that appear likely to be developed in its balancing authority. Several institutional solutions that would relieve or mitigate the burden facing Bonneville’s balancin g authority are being discussed and developed by Bonneville’s Wind Integration Team, which recen tly released a two-year work plan, and by
the ColumbiaGrid/NTTG/WestConnect Joint Initiative, in which Bonneville, as a member of ColumbiaGrid, is participating.

These different kinds of needs can interact with each other. For instance, some kinds of resources that might be valuable for meeting cap acity needs also could provide flexibility for managing wind fluctuations, or, alternatively, resour ces that might be require d to meet flexibility needs, if institutional changes in business prac tices prove insufficient, also could provide resources to meet capacity requirements. Howeve r, the generating resources that might be best at providing flexibility, because they have wide operating ranges, might not be optimized to provide the cheapest energy.

The Council’s analysis, while it looks at re gional capacity and energy requirements, does not break out utility-specific capacity and energy re quirements and does not look at within-hour issues like flexibility. Thus there might be sp ecific Bonneville needs th at are not explicitly addressed in detail in the plan.

First, there are some kinds of resources that the Council considers in it s analysis, both for the plan specifically and for its annual adequacy as sessments, that specific utilities may or may not want to purchase or acquire. Specifically these are out-of-region purchases and in-region uncontracted IPP generation. The Council considers these as available to meet regional loads, but they are not owned or contr acted for by any in-region load-ser ving entity. (For more on this distinction, see Chapter 14.) For any in-region u tility, they are potential resources, like others,
that would need to be evalua ted based on cost and risk.

Second, Chapter 12 of the plan describes variou s ways of meeting flexibility needs (both business practice changes and types of new genera tion). It suggests that the institutional and business practice changes are likely to be th e easiest and cheapest. It does not, however, describe the total amounts of flexibility that w ould be available through all the various business practice changes, or the time fr ame within which they would a ll be available, because those issues are still being examined by vari ous regional and WECC entities.Chapter 13: Bonneville’s Obligations Sixth Power Plan

13-13 Because of this, the plan’s recommendations for Bonneville’s response to Bonneville’s needs described above cannot be precise with regard to specific resources or strategies to meet those needs nor to their timing. Here is a set of ge neral principles Bonneville should follow, with corresponding provisions in the Action Plan:

The first, and major principle, is that Bonnev ille aggressively pursue the Council’s conservation goals. This will ensure that the customer load that remains, whether at Tier 1 or Tier 2 rates, is
as efficient as is cost effective.

A second principle is that Bonneville should aggressively pursue th e various institutional solutions to its balancing needs that are cu rrently being discussed before acquiring power produced by new generation. These institutional ch anges, better forecasting, shorter scheduling windows, markets for the exch ange of balancing services among balancing authorities, generation owners and operators, and demand-res ponse providers, as well as other actions have the potential to be significantly more efficient and faster to develop than new generation to provide these services.

A third principle is that Bonneville should take a broad look at possible resource acquisitions for additional capacity and flexibility, if it turns out that resources are needed to meet its obligations. While Chapter 12 gives an overview of th e business practice ch anges and generating technologies that are available to meet these needs, the possible synergies in simultaneously meeting both capacity and flexibility requireme nts need to be taken into account, and the possibility of newly developed technologies, incl uding a smart grid and storage, should also be considered. Bonneville should take a similarly careful look at possible resource strategies and resources choices, if needed to m eet its obligations in the other areas listed at the beginning of this section, including for reserve and reliab ility requirements and for transmission support.



## Preliminary Conclusions Regard ing Bonneville’s Draft Resource Program

Despite the remaining uncertainties, the Draf t Resource Program characterizes Bonneville’s expectations and intentions sufficiently to be ab le to judge their alignm ent with the Council’s principles and recommendations. Bonneville ha s committed to “ensuring achievement” of the public-power share of the conservation identified in the Council’s plan. The Draft Resource Program says that, depending on the amount of load it must serve, Bonneville will meet most of
the load that remains after conservation with short- to medium-term market purchases. Bonneville also says it intends to investigate othe r resources, as described in the Council's draft
Sixth Plan.

It also describes its efforts to develop new institutional mechan isms and business practices as first approaches to its unmet balancing-resource needs, with investiga tion of other resources, such as those described in the plan, to m eet any remaining flexibility requirements.

Bonneville’s assessment of its pot ential needs and description of proposed actions for meeting those needs in its Draft Resource Program re flect the principles expressed above.Chapter 13: Bonneville’s Obligations Sixth Power Plan

13-14 

## Major Resources

If Bonneville proposes to undert ake a suite of activ ities related to th e acquisition of a major resource, Section 6(c) of the Act requires the Administrator to conduct a public review of the proposal and make findings, taking into account the public comment. A major resource under the Act is one that is greater than 50 average megawatts and is acquired by the Administrator for a period of more than five years. This review provision applies to any pr oposal: (1) to acquire a major generating resource, (2) to implement an e quivalent conservation measure, (3) to pay or reimburse investigation and precons truction expenses for a major res ource, or (4) to grant billing credits or services involving a major resource.

One of the findings Bonneville must make is wh ether a proposed action is consistent with the Council’s plan. After Bonneville has made its finding, the Council has an opportunity to undertake its own review of the proposal to dete rmine consistency with the plan. If either agency finds the proposal inconsistent, Bonneville must get specific authorization from Congress to proceed.



## ASSESSING FISH AND WILDLIFE COSTS AND
ACCOMODATING FISH AND WILDLIFE OPERATIONS

The cost of managing the hydroelectric system to improve conditions for fish and wildlife is largely assigned to the power system, which must not only absorb the fina ncial effects of that operation but also of other expe nditures required to fully implement the fish and wildlife program. In order to do so, the power system mu st generate sufficient revenue to cover all of these financial requirements. The critical elements of the fish and wildlife program that must be integrated with power plan development are pr ojected changes to hydroelectric system energy and peaking capacity capability.

Bonneville uses a well defined method for calculating the cost of fish and wildlife operations, or in other words, the additional revenue requireme nt relative to an operation without fish and wildlife measures. Using this method, Bonneville estimates its total financial obligation for the fish and wildlife program to be $750 to $900 mi llion per year, which includes ordinary and capital expenditures, and power purchases and foregone revenue associated with fish and wildlife operations. Bonneville implements these operations and funds these measures to fulfill its obligations under the Endangered Species Ac t and the Power Act consistent with the Council’s fish and wildlife program.

Specific cost considerations for fish and wildlife are identified in the Northwest Power Act. The language describing the fish and wildlife progr am amendment process [Section 4(h)(6)(C)]
directs the Council to utilize fish and wildlife measures with th e minimum economic cost as long as they achieve the same sound biological objectiv es. To the extent that Bonneville funds fish
and wildlife measures with the minimum ec onomic cost, the expenditures are efficient.

Another section of the Northwest Power Act [4h( 10)(C)] allows Bonneville a credit from the U.S. Treasury for that part of its actual fish a nd wildlife expenditures that can be allocated to non-power purposes of dam operations. The cred it includes a percentage of Bonneville’s power purchases (at market rates) made specifically be cause of fish and wildli fe operations. Forgone revenues, due to bypass spill, are not included in the credit but are counted in Bonneville’sChapter 13: Bonneville’s Obligations Sixth Power Plan

13-15 assessment of total fish and wildlife costs. B onneville has the responsibility to calculate these costs and the Council repor ts them to the governors, Congress, and the region. The Council also independently reviews these cost estimates on occas ion, and will continue to do so in the future.

The Northwest Power Act recognizes that the fe deral Columbia River power system has an
adverse effect on fish and wildlif e in the Columbia and Snake Rive r basins but it also recognizes that the power system has an obligation to mitigate for these impacts by funding additional measures and modifying the operation of the hydroe lectric system as dire cted by the Endangered Species Act and the Power Act consistent with the Council’s fish and wildlife program. The Council’s program ensures that fish and wildlife affected by the federal hydropower system are protected, enhanced, and mitigated and the Counc il recognizes that actions to do so impose an economic cost on the region’s ratepayers. Despite these costs, however they are assessed, the power system remains economical in the broad se nse that power rates remain affordable.

See Appendix M for a description of what the No rthwest Power Act requires in terms of the integration of the Council’s fish and wildlife prog ram into the power plan and the power system, how the power system and resource planning acc ommodates the operations for fish and wildlife purposes over time, and certain opportunities and uncertainties with regard to the continued integration of fish and wildlife and power purposes in the future.Sixth Northwest Conservation and Electric Power Plan 

# Chapter 14: Regional Adequacy Standards

Summary of Key Findings........................................................................................................ ...... 1 Background..................................................................................................................... ................ 2 Motivation for Developing a New Standard............................................................................... 2 Historical Approach............................................................................................................ ........ 3 Adequacy Assessment Efforts Outside of the Northwest........................................................... 3 Assessing the Adequacy of a Resource Strategy ........................................................................ 4 The Pacific Northwest Adequacy Standard .................................................................................... 5 Physical Adequacy, Economic Adequacy, or Both .................................................................... 5 Defining the Resource Adequacy Standard ................................................................................ 6 Annual Needs (Energy Standard) ........................................................................................... 7 Peak Hourly Needs (Capacity Standard) ................................................................................ 7 Implementing th e Standard...................................................................................................... ... 7 Working with Other Entities.................................................................................................... ... 7 The Adequacy of the Northwest Power Supply.............................................................................. 8 Utility Perspective on Resource Adequacy................................................................................... 11 Methodology.................................................................................................................... ............. 14 Analytical Tools............................................................................................................... ......... 14
Reliance on Market Resources.................................................................................................. 1 6 Translating the Adequacy Standa rd into a Simpler Measure.................................................... 17



## SUMMARY OF KEY FINDINGS

The 1990s saw little new resource development in the Northwest due, in part, to the emergence of an electricity market and th e anticipation of deregul ation. As load continued to grow, supply remained stagnant, and utility planners becam e concerned about the adequacy of the power system. 2001 was the second-driest year on record in the Northwest. This, coupled with a failed wholesale power market in California meant the region faced a serious threat of blackouts.
Actions were taken to avoid forced curtailments , but those actions were costly and resulted in soaring electricity prices.

It was becoming obvious that a new method of a ssessing resource adequacy was necessary. The power system was becoming more complex, with gr eater constraints placed on the operation of the hydroelectric system, increasing development of variable and dispersed resources, and the growth of a Westwide electricity market. The Council recognized this need, and in its Fifth Power Plan recommended developing a resource adequacy standard. Supporting this decision was federal legislation, passed in 2005, requiring an Electric Reliability Or ganization (the role now filled by the North American Electric Reli ability Corporation, or NERC) to assess the adequacy of the North American bulk power supply.

In 2005, the Council and the Bonneville Power Ad ministration created the Northwest Resource Adequacy Forum to aid the Council in developi ng a standard, and to annually assess the adequacy of the power supply. The forum, which is open to the public, in cludes utility planners, state utility commission staff, and other interested partie s. After nearly three years of coordinated effort, it reached c onsensus on a proposed resource adequacy standard, which the Council subsequently adopted in April 2008.Chapter 14: Regional Adequacy Standards Sixth Power Plan

14-2 The standard helps to assess wh ether the electricity supply is sufficient to meet the region’s
needs now and in the near future. It provides a minimum threshold that serves as an early warning should resource development fall dangerously short. It also suggests a higher threshold that encourages greater resource development to o ffset electricity price volatility. It does not mandate compliance or enforcement. It does not di rectly apply to individu al utilities – because every utility’s circumstances differ. Individual utilitie s must assess their own needs and risks to determine their own planning targ ets, which are screened by pub lic utility commissions or by
their boards of directors. It w ould be a misapplication of the ad equacy standard to infer that utilities should slow their resource acquisition ac tivity simply because the adequacy standard for the region is being met. The Pacific Northwes t resource adequacy standard can be found at: http://www.nwcouncil.or g/library/2008/2008-07.pdf

.
Over the next five-year period, the region’s ex isting resources, in a ggregate, exceed the standard’s minimum threshold for annual energy n eeds and for winter hourly needs. However, existing resources appear to just barely fall short of meeting the summer hourly adequacy requirement by 2015, which places the region in a yellow-alert status. Under the implementation plan agreed to by forum members, a yellow-aler t status calls for an adequacy report to be
released and for the forum to convene to discuss appropriate actions to take. The forum has met and decided that because the summer capacity shor tfall is minimal and becau se regional utilities are already in a resource- acquisition mode, no additional resource actions should be recommended. However, the forum did reco mmend that all load and resource data be
reevaluated and that the methodol ogy used to define the adequacy standard be peer-reviewed. These actions are currently under way.



## BACKGROUND

Motivation for Developing a New Standard

Economic growth depends on an adequate electric ity supply, and the reso urce adequacy standard was developed to ensure that th e region’s energy needs will be met well into the future. In the worst-case scenario, an inadequate electricity supply can affect public health and safety, as in a blackout. Fortunately, such events are rare, and when they do happen, they are most often caused by a disruption in the delive ry of electricity, not the suppl y. However, there have been times – during extreme cold spells or heat wave s – when supply has been tenuous. The fact that most of the region’s electricity comes from the hydroelectric system presents unique challenges to the energy supply, too, since periods of dr ought that limit hydroelectric power production are unpredictable.

While most disruptions in supply have been shor t-term, the Western United States did experience an extended energy crisis in 2000-01. At its root, the crisis was precipitated by an imbalance of electricity supply and demand centered in Californ ia and the Pacific Nort hwest, where for years development of new energy resources had lagge d behind energy demand. Ripple effects from that crisis were felt throughout th e West as electricity prices and consumer rates soared to historic highs.

In addition, changes in the energy environment have made ensuring the adequacy of the region’s power supply more challenging. Greater constr aints on the operation of the hydroelectric system, increasing development of variable a nd dispersed resources, and the growth of aChapter 14: Regional Adequacy Standards Sixth Power Plan

14-3 Westwide electricity market have all contri buted to creating a much more complex and interconnected power system. Changes in the Bonneville Powe r Administration’s role as a power provider also mean that lo ad-serving entities will bear more responsibility for their load growth, making regional coordination to en sure adequacy especially important.



## Historical Approach

Historically, the Northwest has planned to a critical-water standard, which implies that Northwest resources, including hydroelectric generation pro duced under the driest water condition, should at least match the forecast load on an annual basis. This standard originated when the region was essentially isolated from the rest of the Western system by limited
transmission links. Even after cross-regional interties were built, this policy continued because high oil and gas prices dominated generati on markets in the rest of the West.

However, since the collapse of oil and gas prices in the mid- 1980s, the region has not had to balance in-region resources and demand under critical -water conditions in order to maintain a physically adequate power supply. The reasons fo r this are twofold. In almost all years, hydroelectric generation will ex ceed production under critical -water conditions; and the Southwest should always have surplus winter energy to export (the Southwest is a summerpeaking region and the Northwest is a winter-peaki ng region). Thus, the region has strayed from strict critical-period planning.

Generally, reservoirs behind the dams have been drafted in the fall a nd early winter under the assumption that the region would realize better-tha n-critical water condition s. Should a dry year ensue, the region could import surplus energy fro m the Southwest or inte rrupt a portion of the direct-service industry load. These kinds of c ontractual agreements with the remaining directservice industries no longer exist, but the Northw est is still connected to the Southwest. Both regions should be able to benefit from the divers ity in the timing of their peak loads. A strict assessment of adequacy, therefore, should consider the ability to import power from outside the region. For resource acquisition purposes, howev er, reliance on market resources will depend on impacts to overall cost and customer rates.



## Adequacy Assessment Efforts Ou tside of the Northwest

In order for a regional adequacy standard to be effective, it must be compatible with actions in
the rest of the West. Theref ore, working with the Western Electricity Coordinating Council (WECC) and other Westwide organizations is nece ssary. Most of the di scussions in the region
and the rest of the West have been directed towa rd developing some sort of adequacy standard that would apply to load-serving entities. Th e Federal Energy Regulat ory Commission (FERC) proposed an adequacy standard as part of its st andard market design. However, that standard was inappropriate for an energy-constrai ned, hydropower-dominat ed system like the Northwest’s. The FERC has subsequently deferred to the states, but in the absence of state or regional action, it might attempt to reassert auth ority in this area. In addition, the North American Electric Reliability Corporation (N ERC) has begun developing a power supply adequacy assessment standard that would apply to the WECC.

The NERC Resource and Transmission Adequacy Task Force prepared a report with
recommendations for both resource and transmissi on adequacy. The NERC adopted the report inChapter 14: Regional Adequacy Standards Sixth Power Plan

14-4 2004, and subsequently drafted a standard auth orization request for a resource adequacy assessment incorporating the task force’s r ecommendations. This proposed new standard requires regional reliability counc ils, such as the WECC, to establish resource adequacy assessment frameworks that the NERC will review to ensure compliance.

The WECC has since established a new framewor k that has been implemented in its annual power supply assessments for the last three years. Northwest planners continue to refine the characterization of the Columbia River hydroele ctric system, both for the regional assessment and to improve the accuracy of its adequ acy assessment for the Western Interconnection.

Some states, through their public utility commissions, have the ab ility to implement adequacy standards for the utilities they regulate. For example, the California commission adopted an adequacy standard requiring investor-owned utili ties to have a 15-17 percent reserve margin over their peak load. This planning reserve includes the approximate ly 7-percent operating reserves required by the WECC. The California commission’s order also requires load-serving entities to establish forward contracts to cover 90 per cent of their summer (M ay through September) requirements, which would include their peak lo ad plus the 15-percent reserve one year in advance. Some believe this standard goes beyond what is required to assure adequacy in a purely physical sense, as it is intended to limit California’s expos ure to the risk of extreme prices.



## Assessing the Adequacy of a Resource Strategy

Assessing the adequacy of the Council’s long-ter m resource strategy, as outlined in this power plan, is a separate issue from assessing the adequacy of the existing power system through the next five years. This section describes how those assessments differ and how the Council’s resource adequacy standard is incorporated into its planning models to en sure that the resulting long-term strategy will provide an adequate supply.

The Northwest resource adequacy standard is based on a probabilistic metric defined by the resource adequacy forum that assesses whether ex isting resource capability is sufficient to meet firm loads through the next five years. That assessment takes into account only existing resources and new resources that are expected to be completed and operational during that time period. If a deficiency is iden tified, then specific actions are initiated. Those actions include reporting the problem, validating load and resource data used in the assessment and identifying potential solutions.

The process described above is inte nded to be an early-warning system for the region to indicate when the capability of the existing power system does not sufficiently keep up with demand. Although similar, an assessment of a resource strategy differs in significant ways. First, a resource strategy spans a much longer time peri od, namely 20 years for the Council’s power plan. Second, a strategy implies that resource development will be dynamic, in other words, it provides a supply of cost-effectiv e resources that the region can draw from depending on future conditions. The adequacy of a single resource plan (i.e. the resource-construction dates for a specific future simulated by the Council’s regional portfolio model) can be assessed, but that is not the same as assessing the adequacy of the strategy itself.Chapter 14: Regional Adequacy Standards Sixth Power Plan

14-5 What does it mean, then, to assess the adequacy of a resource strategy? In particular, how can we ensure that this power plan will provide an adequate supply? One approach is to assess the adequacy of each resource plan associated with each future simulated by the portfolio model (750 futures). But how many of those plans must pass the adequacy test in order for the strategy itself to be deemed adequate? If every plan is adequate, then we can be reasonably sure that the strategy is adequate. Unfortunate ly, that outcome is unlikely beca use of the number and range of uncertain variables used in the model. So, what percentage of possible future plans (derived from the resource strategy) must pa ss the test in order for the strate gy to be deemed adequate?

The adequacy forum has not addressed this spec ific issue because it is somewhat outside the scope of its tasks. However, there is an altern ative approach that prov ides a viable solution. Rather than assessing the adequacy of specific resource plans as a post process, the adequacy standard can be incorporated di rectly into the portfolio model. The standard is based on a probabilistic analysis that assesses the likelihood of curtai lment to service (further defined in the next section). The result of that probabilistic analysis is transl ated into a minimum load/resource balance threshold. When a resource plan meet s or exceeds this threshold, it satisfies the adequacy requirement. To ensure that the power plan’s resource strategy is adequate, this minimum threshold has been added to the por tfolio model as a requirement for resource acquisition. In other words, if the model’ s resource acquisitions (based on economic considerations) do not measure up to this thresh old, it will add resources until that condition is
satisfied.



## THE PACIFIC NORTHWEST ADEQUACY STANDARD

The adequacy forum includes representatives from the region’s electric utilities and utility organizations, public utility commissions and public interest groups, as we ll as from Bonneville and the Council. It is made up of a st eering committee and a technical committee.

The forum’s overarching goal is to “establish a resource adequacy framework for the Pacific Northwest to provide a clear, consistent, and unambiguous means of answering the question of whether the region has adequate deliverable reso urces to meet its load reliably and to develop an effective implementation framework.”

To that end, the forum has forged a voluntary, cons ensus-based standard for the region to address both energy (annual) and capacity (hourly) needs. This standard has been designed to assess whether the region has sufficient resources to meet growing demand for electricity well into the future. This is important, because it takes time – usually years – to acquire or construct the necessary infrastructure for an adequate electricity supply.

While some interests may wish to see an enforc eable adequacy standard, currently, there are no
institutions in the Northwest that could enforce such a standard for all the region’s load-serving
entities.



## Physical Adequacy, Economic Adequacy, or Both

Is the purpose of an adequacy standard to ensure that the “lights stay on” with an acceptably high probability (physical adequacy); or is it to prot ect against the economic and social costs of an energy shortage (economic adequacy)? The ad equacy standard addre sses the first level byChapter 14: Regional Adequacy Standards Sixth Power Plan

14-6 providing a minimum threshold that serves as an early warning should re source development fall dangerously short. The standard also suggest s a higher threshold that encourages greater resource development to offset electricity pr ice volatility -- or economic adequacy. The
economic threshold is tied to th e resource strategy defined in the Council’s power plan. The forum has not yet fully explored this interpretati on of the economic threshold nor has it made any recommendations regarding failure to meet that threshold.

Different adequacy standards could be applied at different levels. For instance, a physical standard might be most appropriately applied at the WECC level. At this level, it would provide a baseline for physical reliability and actions by load-serving entities and their regulators to address. Economic adequacy might be better addressed at the indivi dual (or perhaps state policy) level, where different mechanisms for mitigating price risk could be put in place.

Unlike past adequacy assessments, this assessmen t considers the question of reliance on market supply. Physical adequacy is determined by fore cast load, existing firm resources, and assessing available market supply, cost notwithstanding. Economic adequacy is determined in a similar manner, except that the region (or utility) uses an economic analysis or makes a policy decision to determine how much power to buy from the market. Utilities may want to limit their exposure
to market resources for a number of r easons, price volatility being only one.

The Council’s portfolio analysis results suggest maintaining a highe r level of in-region resources than the adequacy standard’s minimum threshold. These additional resources reduce the likelihood of having to purchase high-priced electri city. At the same time, however, the analysis
also indicates that if the overall level of regional resources is su fficient, overbuilding is a riskier and more expensive alternative than some level of reliance on the market. This is true regardless of the ownership of the resources. 1 The challenge is to fi nd the right balance.



## Defining the Resource Adequacy Standard

The Northwest resource adequacy standard 2 is based on a sophisticat ed hourly assessment of load and resources and how they might be affected by temperature (load deviations), precipitation (water supply), forced outages to generating resources, a nd other factors.

Historically, the region’s tolerance for a signific ant power supply shortage has been assumed to be 5 percent – that is, the regi on would tolerate a significant pow er shortage no more than once in 20 years. This type of metric is commonl y referred to as a loss-of-load probability (LOLP) and requires a complicated computer model to as sess. However, not all utilities or other planning entities are willing or able to use such a tool. Ther efore, the LOLP threshold is translated into a simpler and more familiar load/resource balance measurement that regional planners can use more easily. These simpler me asurements are provided both for annual energy needs and peak hourly capacity needs.

1 Ownership refers to either utility ownership or ownership by independent power producers.
2 The Northwest resource adequacy standard can be found at: http://www.nwcouncil.org/ener gy/resource/Default.asp

.Chapter 14: Regional Adequacy Standards Sixth Power Plan

14-7 

### Annual Needs (Energy Standard)
Energy in this context refers to the annual electricity ne eds of the region. The measure for this is the annual average load/resource ba lance in units of average mega watts. The threshold for this measure is set so that the resulting LOLP assessm ent yields a 5-percent value. In determining resource generating capability, the standard in cludes hydroelectric generation available under critical-water conditions, available annual output of regionally committed thermal generators and renewable resources, and a portion of the uncom mitted independent power producer generation.
The standard also includes a sm all amount of non-firm resources such as out-of-region market supplies and non-firm hydroelect ric generation. The amount of non-firm resources the region should rely on is determined by th e 5-percent LOLP analysis. In determining load, the standard uses the region’s average annual firm load base d on normal temperatures, and adjusted for firm out-of-region energy contract sales and purchas es and savings from conservation programs.



### Peak Hourly Needs (Capacity Standard)
Capacity in this context refers to the peak hourly electricity needs of th e region. The measure for this is the planning reserve margin, or the surplus sustained-peaking capacity, in units of percent. It represents the surplus gene rating capability above the sust ained-peak period demand. In determining the planning reserve margin, the standard includes the same firm and non-firm resources used to assess the energy standard fo r the region. The planning reserve margin is assessed over the six highest load hours of the day for three consecutive days (sustained-peak period). This is intended to simulate a cold snap or heat wave – periods of the year when the Northwest requires the most capacity. The plan ning reserve margin is computed relative to normal-weather sustained-peak load. The thresh old for this measure is determined by the 5- percent LOLP analysis and should be sufficien t to cover load deviations due to extreme temperatures and the loss of some generating capability.



## Implementing the Standard

The forum wanted to ensure it did not overstep th e jurisdiction of states or the prerogatives of individual utilities in planning and acquiring resources to meet load. Because each utility’s circumstances differ, it is difficult to translate a re gional standard into a u tility-specific standard. The forum has provided some guidance for utilities, but ultimately, they a nd their regulators are the decision-makers for resource acquisition. The implementation plan depends on regional sharing of information, transp arency of assessment methodologi es, and regional coordination.
The forum believes that a voluntar y approach will work because utilities and their governing bodies have a strong incentive to develop ad equate resources to meet retail load.



## Working with Other Entities

The Council, in conjunction with the forum, w ill assess the adequacy of the region’s power supply on an annual basis. Demand forecast and re source assumptions will be compared to those in other regional reports, such as Bonneville’ s White Book and the Paci fic Northwest Utilities
Conference Committee’s Northwest Re gional Forecast. This sharing of information in a public forum should provide a favorable environment fo r addressing inconsis tencies in data and reporting standards.Chapter 14: Regional Adequacy Standards Sixth Power Plan

14-8 The Northwest is not alone in focusing on ensu ring an adequate power supply. The NERC was expected to pick up its previ ously delayed work on the develo pment of a resource adequacy assessment standard in 2009, which is expected to require the WECC to develop an adequacy assessment framework, but the standard devel opment has since slipped. The WECC has spent the past several years developing a framework for the West’s power supply, which is currently in place. The WECC’s framework is not intended to override any state or regional assessments, including regional adequacy measures or their thresholds. In fact, the WECC has solicited help from regional entities to aid in its assessment of Westwide resource ad equacy. The Council and the forum will continue to participate in the WECC’s efforts.



## THE ADEQUACY OF THE NORTHWEST POWER SUPPLY

The adequacy standard calls for the average annual energy capability to at least equal the average annual demand. It also calls for the system’s p eaking capability to be able to meet expected peak-hour demand and to have sufficient surplus to cover operating reserves, 3 prolonged generator forced outages, and demand deviations due to extreme temperatures. Key findings of
the current assessment are:

• Based only on existing resources (and those under constructi on), the region’s power supply may fail to provide sufficient su mmer peaking capability by 2015 although not by
much.

• This puts the region in a “yellow alert” situa tion, which triggers specific actions that require a review of all load and resource da ta and a review of the methodology used to assess adequacy. This work is underway.

• The Council and regional util ities are actively developing re source-acquisition strategies, which take economic risk, carbon-emission policie s and other factors into account.

• Adding expected resource additions derived from the Council’s power plan keeps the power supply adequate nearly through the entire study horizon period.

The Northwest adequacy standard, developed by the forum and adopted by the Council in 2008, specifies minimum thresholds for annual ener gy load/resource balanc e and for winter and summer surplus capacity margins. Normally the adequacy assessment is targeted for three and five years out, but in this instance the assessmen t is for the 20-year hori zon of the power plan. Figures 14-1 through 14-3 show the assessed annu al load/resource balanc e and capacity-reserve margins through the year 2030.

As apparent in Figure 14-1, only counting exis ting firm resources, the region is in about load/resource balance today, which (without any new resources) grows to a large deficit by 2030 (black line). The standard, how ever, includes some non-firm resources in its definition of the load/resource balance for adequacy purposes . A planning adjustme nt of 1,300 average megawatts is included to account for out-of-re gion market supplies and some amount of non-

3 Operating reserves currently do not include additional regulating or load-following reserves anticipated to be needed to integrate large amounts of new wind generatio n into the regional power grid, primarily because these reserves have not yet been quantified. In addition, th is assessment only includes existing wind facilities and those currently under construction.Chapter 14: Regional Adequacy Standards Sixth Power Plan

14-9 firm hydroelectric generation. The assessment also includes the full annual availability of regionally owned resources. This value is estimated to be about 1,600 average megawatts greater than the aggregat e total of utility-declared firm non-hy dro resources. Finally, there is a substantial amount of within-region but uncomm itted generation, namely the independent power producer resources, which add a bout 2,150 average megawatts to the balance. Adding the nonfirm resources to the calculation yields the soli d red line in Figure 14-1, which shows the region well above the adequacy threshold until about 20 27 (red line). Adding new resources suggested by the power plan (averaged over all futures) increases the surplus re lative to a physical adequacy need (but are needed for econo mic and risk-aversion purposes).

Figure 14-1: Energy Adequacy Assessment

-8000 -6000 -4000 -2000 0 2000 4000 6000 8000 1000020102012201420162018202020222024202620282030Average MW

Plan Adjust In-region

IPP

Utility
Nonfirm Adequacy Balance

Existing Firm With Plan Resources

Threshold

In a similar fashion, the winter and summer surplus sustained- peaking reserve margins can be calculated and compared to their adequacy th resholds. Figures 14-2 and 14-3 show those assessments for January and July, respectively. The sustained-peak reserve margin represents the amount of surplus generating capacity over the expected demand averaged over the sustained peak period, in terms of percent. The sustained peak period is defined to be the six highest load hours per day over three consecutive days (to reflect the duration of a typical cold snap or heat wave). As with the energy assessment, countin g only existing firm resources shows the region below the January minimum capacity threshold fo r the entire planning horizon (black line). Adding non-firm resources, as defined in the stan dard (and described below), raises the reserve margin above the threshold until about 2030. Ag ain, adding the expected generation from power plan resources makes the reserve margin even higher.

For theses capacity adequacy assessments, the fo llowing non-firm resources were assumed to be available during emergency conditions. For wint er months, in-region IPP generation is assumed to be fully available at 3,550 megawatts but for su mmer months that availability is reduced to 1,000 megawatts. Additional hydroelectric generation, in excess of critical-period generation, is assumed to be 2,000 megawatts in winter and 1,0 00 megawatts in summer. Finally, a maximum of 3,000 megawatts of out-of-region supply is as sumed for winter but none for summer.Chapter 14: Regional Adequacy Standards Sixth Power Plan

14-10 The story is a little different for July. Looking at Figure 14-3, the reserve margin, including defined non-firm resources, only keeps the regi on above the minimum threshold through about 2015. According to the standard, this puts the re gion in a “yellow-alert” situation, triggering specific regional actions, which currently are under way. First, regional planners are reviewing all load and resource data. Second, the methodol ogy used to assess the minimum thresholds is being reviewed. Third, the Council and region al utilities are activ ely developing resourceacquisition strategies.

Adding expected new resource capability, based on the Council’s plan, to the reserve margin calculation in Figure 14-3 (topmost dashed line) indicates that the power supply should remain above the minimum adequacy threshold throughout nearly the entire stud y horizon. However, it should again be emphasized (see the above se ction entitled “Assessing the Adequacy of a Resource Strategy”) that using th is type of static diagram (as in Figure 14-3) to assess the adequacy of the power plan’s strategy is inappr opriate. Future resource acquisitions based on the plan’s strategy will vary depending on forecasts of future conditions. The dashed line in Figure 14-3 reflects new resource capabil ity averaged across all futures an alyzed by the portfolio model. The fact that it dips below the minimum ade quacy threshold in 2029 provides no indication of the adequacy of the plan’s resource strategy. The proper use of Figures 14-1 through 14-3 is to compare the adequacy metrics (red lines), as defined by the standard, to their minimum thresholds (blue lines) over the next five-year period only. The r eason the curves in these charts were extended to a 20-year period was only to indicate generally how the plan’s average resource build-out compares to the minimum th resholds -- not to assess the adequacy of the plan’s resource strategy.

Figure 14-2: January Capacity Adequacy Assessment

-10%

0% 10% 20% 30% 40% 50% 60% 70%20102012201420162018202020222024202620282030Sustained Peak Reserve Margin

With Plan Resources

Hydro
Flex In-region

IPP
SW
Market Adequacy Reserve

Existing Firm ThresholdChapter 14: Regional Adequacy Standards Sixth Power Plan

14-11 Figure 14-3: July Capacity Adequacy Assessment

-10%

-5% 0% 5% 10% 15% 20% 25% 30% 35% 40%20102012201420162018202020222024202620282030Sustained Peak Reserve Margin

Plan
Resource

Hydro
Flex In-region

IPP With Plan Resources

Existin g Firm Adequacy RM Threshold



## UTILITY PERSPECTIVE ON RESOURCE ADEQUACY

As discussed in Chapter 3, regional utilities historically have used the annual average load/resource balance as a simple metric to get an indication of their resource needs. This utility perspective compares only firm loads to firm resources (which include critical-period hydroelectric generation). The general conclusions th at can be drawn from this simple metric is that when the average annual load is greater than the firm suppl y, additional resources likely are needed. And, as illustrated in Figures 3-13 through 3-15 in Chapter 3, the region’s firm
resources fall short of forecasted demand within the next five-year pe riod, both for annual energy and hourly capacity needs. Utilities understand, however, that this is only a rough estimate at best and decisions regarding ne w resource acquisition must be ma de using more sophisticated analysis.

Nonetheless, the firm load/resource balance metr ic still provides a useful guide in assessing future power supply needs. Figures 14-4 throug h 14-6 show the balance between firm resources and load for annual energy and hourly capacity need s. These figures are identical to Figures 3- 13 through 3-15 except for the addition of planned resources derived from the Council’s resource strategy. Figure 14-4 indicates that on a firm ba sis only, existing resources combined with the expected resource development from this power plan will be suffici ent to cover the entire range of load uncertainty. It should be noted that th ese results reflect the st atus of the region, in aggregate. Individual utility plans will differ based on their specific conditions and needs.

Another interesting result is reflected in the range of new resource additions. The purple area in Figure 14-4 reflects resources acquired in response to the low end of the load forecast range. The small pink area in this figure represents the additional resources acquired in response to the high end of the load forecast range. (The high en d values are averaged over the top 100 futures analyzed by the portfolio model and the low end values are averaged over the bottom 100 futures). The interesting thing about this result is that almost regardless of load, the model suggests a high level of resource energy developmen t. Most of the new resources (on the orderChapter 14: Regional Adequacy Standards Sixth Power Plan

14-12 of 85 percent) are made up of conservation measur es. Based on these results, we can infer that the model is acquiring this level of resource because it is economic to do so and because it minimizes exposure to other risks, such as ca rbon penalties -- not necessarily because of adequacy needs.

Figure 14-4: Energy Firm Loads and Resources

- 5,000 10,000 15,000 20,000 25,000 30,000 35,000

2010 2011 2012 2013 2014 2015 201 6

201 7

2018 2019 202 0

202 1

2022 2023 2 024 2 025 2026 2027 2028 2029

Existing Firm Resources New Resource Additions
New Resource Addition Range Load Range

Figures 14-5 and 14-6 provide similar load and re source information for the region’s winter and summer hourly needs. As in Figure 14-4, the re sources depicted in these figures include only firm resources and planned resources derived from the portfolio model an alysis. The generating capability of resources shown in these figures reflect their sustained-peak capability, that is, what these resources reliably can generate on average over the six highest load hours of the day for three consecutive days. The lo ad forecasts in these figures do not include any amount of sustained-peak reserve margin requirement.

For both January and July, existing firm and portf olio-model planned resources are sufficient to cover the entire sustained-peak load forecast range throughout the study horizon. However it is
not clear whether those resources would be sufficient to satisf y reserve-margin requirements throughout the study horizon. Figures 14-7 and 14-8 chart the resulting su stained-peak reserve margin ranges for January and July, respectivel y. Unfortunately, no util ity-perspective (firm only) sustained-peak reserve-marg in requirements have been estab lished for the Northwest. If these requirements were known, Figures 14-7 and 14- 8 could be used to identify years when the power supply fails to meet its hourly needs.

For January, in Figure 14-7, the entire range of sustained-peak reserve margin stays above the 20-percent level throughout the study horizon. If the utility-perspective su stained-peak reserve margin threshold were 17 percent (see Chapte r 3), for example, then January would show no capacity deficiency, on average. Keep in mind that plan resources added to existing resources in these figures are averaged over all simulated futu res, thus this conclusion cannot be made for
each future condition.Chapter 14: Regional Adequacy Standards Sixth Power Plan

14-13 For July, in Figure 14-8, the bottom end of the reserve-margin range drops below 17 percent by about 2024, which implies that existing resources plus plan resources would not be sufficient to cover loads plus reserve requirements by that ye ar. However, these results do not provide an accurate assessment of hourly needs.

Figure 14-5: January Sustained-Peak Period (SPP) Loads and Resources

- 5,000 10,000 15,000 20,000 25,000 30,000 35,000 40,000 45,000 50,000

2010 201 1

2012 2013 2014 2015 2016 2017 2018 201 9

2020 2021 2022 2023 2024 2025 202 6

202 7

2028 2029

Existing Firm Capacity New Capacity
New Capacity Range SPP Peak Load Range

Figure 14-6: July Sustained-Peak P eriod (SPP) Loads and Resources

- 5,000 10,000 15,000 20,000 25,000 30,000 35,000 40,000 45,000

2 0

10

20

1 1

20

12

2013 20

14

2015 20

16

2017 20

18

2 0

19

20

20

2 0

21

20

2 2

20

23

2024 20

25

2026 20

27

2028 20

29

Existing Firm Capacity New Capacity New Capacity Range SPP Peak Load RangeChapter 14: Regional Adequacy Standards Sixth Power Plan

14-14 Figure 14-7: January Sustained-Peak Period Reserve Margins

0% 10% 20% 30% 40% 50% 2010 2011 201 2

201 3

201 4

2015 2016 2017 2018 2019 2020 2021 2022 2023 202 4

2025 2026 2027 2028 2029

Max RM

Min RM

Figure 14-8: July Sustained-P eak Period Reserve Margins

0% 10% 20% 30% 40% 50% 2010 201 1

201 2

2 013 2014 2015 2016 2017 2018 201 9

2020 2021 2022 2023 2024 2025 2026 2027 2028 2029

Max RM

Min RM



## METHODOLOGY

Analytical Tools

The Council used two complementary analyses to develop the adequacy standard. One addresses physical adequacy – the ability to meet load. The other addresses economic adequacy – avoiding extremely high costs that can result from tight su pply conditions. The first analysis uses the GENESYS model, which performs a detailed si mulation of the Northwest power system toChapter 14: Regional Adequacy Standards Sixth Power Plan

14-15 assess the ability of the system to meet load with variations in future conditions. The second analysis uses the portfolio model, described in Chapter 9, to explore the cost/risk tradeoff over a large number of possible futures.

The GENESYS model was developed in 1999 to a ssess the adequacy of the regional power supply. 4 One of its most important features is that it is a probabilistic model, that is, it incorporates future uncertaintie s into its analysis. Each GE NESYS study involves hundreds of simulations of the operation of the power system. Each simulation is performed using different values for uncertain future variables, such as pr ecipitation (which affects the amount of water for hydroelectric generation) and temperature (whi ch affects the demand for electricity).

More precisely, the random (or uncer tain) variables modeled in GENESYS are Pacific Northwest streamflows, Paci fic Northwest demand, generati ng-unit forced outages, and variability in wind generation. The variation in streamflow is cap tured by incorporating the 70- year (1929–1998) Pacific Northwes t streamflow record. Uncertainty in demand is captured by using the Council’s short-term (tempera ture-driven) demand model.

GENESYS does not model long-term demand uncertainty (unrelated to temper ature variations in demand) nor does it incorporate any mechanism to add new resources should demand grow more rapidly than expected. It performs its calcu lations for a known system configuration and a known long-term demand forecast, which can change over time. In order to assess the physical adequacy of the system over different long-te rm demand scenarios, the model must be rerun using the new demand and the corresponding new re source additions. The portfolio model deals with long-term demand uncertainty explicitly, as well as with ot her long-term uncertainties.

Another important feature of GENESYS is that it captures the effects of hydropower flexibility, that is, the ability to draft reservoirs below normal drafting limits during emergencies. Hydropower flexibility can be particularly im portant in helping address potential supply problems during extended periods of high demand from extreme cold events (or heat waves). In order for GENESYS to properly assess the use of this emergency generation, a very detailed hydroelectric-operation simulation algorithm was incorporated in to the model. This logic simulates the operation of the hydroe lectric system on an hourly ba sis. The portfolio model has a much more simplistic repres entation of the hydroelectric sy stem and simulates resource dispatch on a seasonal basis.

The probabilistic assessment of adequacy in GE NESYS provides much more useful information to decision-makers than a simple determinis tic (static) comparison between resources and demand. Besides the expected values for hydroe lectric generation and dispatched hours for thermal resources, the model also provides the distri bution (or range ) of operations for each
resource. It also includes situ ations when the power supply is not able to meet all of its obligations. These situations are informative because they identify the conditions under which the power supply is inadequate. The frequenc y, duration, and magnitude of these curtailment events are recorded so that the overall probabili ty of not being able to fully serve load is calculated. This probability, commonl y referred to as the loss-of-load probability (LOLP), is the figure of merit provided by GENESYS.

4 Northwest Power Supply Adequacy/Reliability Study Phase 1 Report, Council Document 2000-4, March, 2000. http://www.nwcouncil.org/library/2000/2000-4.pdfChapter 14: Regional Adequacy Standards Sixth Power Plan

14-16 It should be noted that in determining the LOLP , an assumption is made in GENESYS that all available resources will be disp atched in economic order to “k eep the lights on,” no matter what the cost. As such, the LOLP is a physical, rather than an economic, metric.

For the Northwest, the Council has defined an ade quate system to have an LOLP no greater than 5 percent. This means that of all the si mulations run, with uncertain water conditions, temperatures, forced outages, and variable wind, no more than 5 pe rcent had significant curtailments. Such a system faces a maximu m 5-percent likelihood that some demand will not be served due to inadequacies in the generati on system (not counting potential problems in the transmission network).

But what constitutes a significant curtailment event? Because the GENESYS model cannot possibly simulate all potentially varying parameters or know precise ly every single resource that is available, a threshold is used to screen out inconsequential curtailment events. This threshold is commonly referred to as a “co ntingency” resource and depict s the amount and characteristics of additional generation available to utilities during emergencies.



## Reliance on Market Resources

Assessing power supply adequacy is very sensitiv e to assumptions regarding market supplies, whether they come from within or outside th e region. But how much of the market supply should the region rely on for adequacy? Assumi ng that no supply is avai lable is probably too conservative, as it will result in greater resource acquisition and be more costly in the long run. And although relying more on mark et supplies could lower long-term costs, year-to-year price volatility could be extreme. Therefore, some level in between, calculated with the tradeoff between risk and cost in mind, is used for planning purposes.

Figure 14-9 illustrates the relationship between the LOLP and available market supply (presented in units of capacity), for different levels of Northwest firm load/resource balance. Generally speaking, the more the market supply, the lower th e LOLP will be. For example, consider the case where the region is 2,000 average megawatts de ficit on a firm basis (the curve with the diamond-shaped points in Figure 14-9). Assuming th at a 5-percent LOLP represents an adequate power supply, the Northwest would be adequate (even though the load/resource balance is negative) if at least 4,00 0 megawatts of market supply were av ailable. If no market supply were available, the projected LOLP would be on th e order of 25 percent -- well over the minimum threshold of 5 percent. Even if the Northwest were in load/resource balance (the far left curve with the triangular points), the LOLP would be slightly over 5 pe rcent with no available market supply.Chapter 14: Regional Adequacy Standards Sixth Power Plan

14-17 Figure 14-9: Illustrative Exam ple: LOLP as a Function of Available Southwest Capacity
for Different Load/Resource Balance Conditions

0 5 10 15 200100020003000400050006000700080009000

SW Winter Surplus (MW)LOLP (Percent) Bal = 0

Bal = -1000

Bal = -2000

Bal = -3000

Bal = -4000



## Translating the Adequacy Standard into a Simpler Measure

To make the relationship between the LOLP and market supply a little easier to see, the values in Figure 14-9 for all the points that cross the 5-per cent LOLP level are plotted in Figure 14-10. In that figure, every point on the plotted curve re presents the same adequacy, namely a 5-percent LOLP. Given a particular load/resource balance in the Northwest (horizontal axis), this graph shows how much market supply (vertical axis) is required to maintain an adequate system. Again, using the same example, if the region wa s deficit by 2,000 average megawatts (on a firm basis), it would require about 4,000 megawatts of market supply from the Southwest surplus in order for the Northwest to maintain a 5-percent LOLP. This does not mean that the region would import 4,000 megawatts, but it does mean that in some hours the full 4,000 megawatts could be imported.Chapter 14: Regional Adequacy Standards Sixth Power Plan

14-18 Figure 14-10: Illustrative Example Relati onship between SW Surplus Capacity and
Load/Resource Balance

0 2000 4000 6000 8000 10000

0 1000 2000 3000 4000 5000

Annual Critical Water Firm Deficit (MWa)SW Winter Surplus Capacity (MW) Constant 5 % LOLP

The question of how much out-o f-region surplus the Northwes t should rely on for planning purposes, however, ends up being a policy question. If California goes forward with aggressive adequacy standards, it should mean that Californ ia will have ample winter surplus for years to come. However, current and potentially new ai r quality concerns may limit the operation of surplus resources in California. In addition, the potential of a future carbon tax may diminish their availability to th e Northwest. Based on recent analysis , the current (arguably conservative) analysis assumes a 3,000-megawatt supply of out -of-region surplus capacity during winter months and no surplus capacity during summer months.

The in-region market supply is composed of independent power producer (IPP) resources, which are sold to the highest bidder, whether inside or outside the region. Current estimates show about 3,500 megawatts of such resources in the No rthwest. During winter months, assuming that the Southwest is surplus, all of the IPP market supply should be available for Northwest use. However, during summer months, when Northwes t utilities must comp ete with Southwest utilities for access to IPP genera tion, only a portion of their generati on is assumed to be available for adequacy assessments. An estimate of availa ble summer IPP generation for Northwest use is determined by their access to interregional tran smission. IPP resources that have no direct access to interregional transmission are assumed to be available for Northwest use. Current adequacy assessments assume that 1,000 megawatts of IPP generation is available for summer use. Thus, for capacity assessments, 3,500 megawa tts of IPP generation is assumed for winter and 1,000 megawatts are assumed for summer. For energy assessments, about 2,100 average megawatts of IPP annual average generation is assumed.Chapter 14: Regional Adequacy Standards Sixth Power Plan

14-19 By using the relationship in Figure 14-10 and assuming that 3,000 mega watts of out-of-region surplus capacity is available, regional pla nners can assess the minimum balance between resources and loads that will yield an adequate supply (5 percent LOLP). Based on current analysis, that minimum for annual energy needs is a 1,300-average-megawatt deficit. In other words, counting only Northwest firm and IPP resources, the region’s power supply can be no lower than 1,300 average megawatts less than firm loads in order to maintain an adequate supply. This means that, on average, the region can depend on 1,300 average megawatts from non-firm hydroelectric power and out-of-region supplies. A similar analysis and relationship is used to assess the minimum threshold for hourly needs.