# Best Practices in Electric Utility Integrated Resource Planning

Examples of State Regulations and Recent Utility Plans

Authors 

## Rachel Wilson Bruce Biewald

June 2013Electronic copies of this paper and other RAP publications can be found on our website at www.raponline.org

. To be added to our distribution list, please send relevant contact information to info@raponline.org

. 

## About The Regulatory Assistance Project (RAP)

The Regulatory Assistance Project (RAP) is a global, non-profit team of experts focusing on the long-term economic and environmental sustainability of the power and natural gas sectors. RAP has deep expertise in regulatory and market policies that promote economic efficiency, protect the environment, ensure system reliability, and allocate system benefits and costs fairly among all consumers.

RAP works extensively in the European Union, the US, China, and India. We have assisted governments in more than 25 nations and 50 states and provinces. In Europe, RAP maintains offices in Brussels and Berlin, with a team of more than 10 professional experts in power systems, regulation, and environmental policy. For additional information, visit the RAP website www.raponline.org. Prepared by Synapse Energy Economics

for the Regulatory Assistance Project. Funding provided by the Southern Alliance for Clean Energy.

Unless otherwise indicated, figures are created by Synapse Energy Economics based upon analysis herein.1 

# Table of Contents

Executive Summary

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2

Introduction

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3
I. The Purpose and Use of Integrated Resource Planning

. . . . . . . . . . . . . . . . . . . . . . . . . 4
II. Examples of State Integrated Resource Planning Statutes and Regulations

. . . . . . . . . . 6

A. Arizona

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9

B. Colorado

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11
C. Oregon

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13
III. Examples of Best Practices in Utility Integrated Resource Plans

. . . . . . . . . . . . . . . . . 16

A. Arizona Public Service

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16
B. Public Service Company of Colorado

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19
C. PacifiCorp

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22
IV. Recommendations for Prudent Integrated Resource Planning

. . . . . . . . . . . . . . . . . . 26
A. Integrated Resource Planning Process

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26
1. Resource Plan Development

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26

2. Resource Plan Review

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27
B. Integrated Resource Plans

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28

V. Conclusion

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33
Appendix: State IRP Statutes and Rules

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 342 

# A n integrated resource plan is a utility plan for meeting forecasted annual peak and energy demand, plus some established reserve margin, through a combination of supply-side and demand-side resources over a specified future period. For utilities, integrated resource planning is often quite time- and resource-intensive. Its benefits are so great, however, particularly to consumers, that utilities are frequently required by state legislation or regulation to undertake planning efforts that are then reviewed by state public utilities commissions (PUCs). (In this document, the acronym IRP is used, depending on the context, to denote either an integrated resource plan or the process of integrated resource planning.) IRP rules governing utilities have been created in a number of ways. Bills that mandate integrated resource planning have been passed into law by state legislatures; rules have been codified under state administrative code; and state utility commissions have adopted IRP regulations as part of their administrative rules, or have ordered it to be done as a result of docketed proceedings. Although some state IRP rules have remained unchanged since they were first implemented, other states have amended, repealed, and in some cases reinstated their IRP rules. Examples can be found in the rules of Arizona, Colorado, and Oregon. Rules that have been amended recently often reflect current concerns in the electric industry—e.g., fuel costs and 

# Executive Summary

volatility, the effects of power generation on air and water, issues of national security, electricity market conditions, and climate change, as well as individual state concerns. There are, however, certain subject-matter areas that are essential to resource planning on which state regulations are silent. Utilities must use their discretion in determining how best to address these areas in their resource plans. This paper provides utilities, commissions, and legislatures with guidance on these subject-matter areas. Section III summarizes three recent utility IRPs from the states mentioned above, in an effort to determine both best practices in integrated resource planning and ways in which utilities can improve their planning processes and outcomes. Section IV then presents a series of recommendations, developed from these examples, for integrated resource planning and its resulting plans. For an IRP process to be deemed successful, it should include both a meaningful stakeholder process and oversight from an engaged public utilities commission. A successful utility’s resource plan should include consideration in detail of the following elements: a load forecast, reserves and reliability, demand-side management, supply options, fuel prices, environmental costs and constraints, evaluation of existing resources, integrated analysis, time frame, uncertainty, valuing and selecting plans, action plan, and documentation. Section IV describes in detail the elements of both the process and the plan.3 

# A s energy demand across the United States rises and falls and the generation fleet ages, utilities must plan to add and retire resources in the most cost-effective manner while meeting regional reliability standards. Integrated resource planning began in the late 1980s, as states looked for a way to respond to the oil embargos and nuclear cost overruns of the previous decade—and ever since, it has been an accepted way in which utilities can create long-term resource plans. State requirements for resource plans vary in terms, among other things, of planning horizon, the frequency with which plans must be updated, the resources required to be considered, stakeholder involvement, and the actions that public utilities commissions should take in reference to the plan (review, acknowledge, and accept or reject the plan).As the electric industry began to restructure in the mid1990s, integrated resource planning rules in many states were repealed or ignored. Some states have since made an effort to update IRP rules to make them applicable to current industry conditions, while other states have continued to use rules that are now out of date. This report describes IRP requirements in three states that have recently updated their regulations governing the planning process, and it reviews the most recent resource plan 

# Introduction

from the largest utility in each of those states. Rules from Arizona, Colorado and Oregon are described in detail, in order to demonstrate ways in which states can require comprehensive planning processes and resource plan outcomes from the utilities under their jurisdictions. These particular states were chosen not only because their rules have recently been updated, but also because the guidance they provide to electric utilities offers examples of best practices in integrated resource planning. The updated rules have been designed to give thoughtful consideration to specific resources that have traditionally been ignored, and to produce outcomes that are in the best interests of both ratepayers and society as a whole. Utility resource plans from Arizona Public Service, Public Service Company of Colorado, and PacifiCorp utilize progressive methodologies and contain modern elements that contribute to the production of high-quality plans that are useful examples of superior resource planning efforts. This report is intended to be helpful to policymakers, public utility commissions and their staff, ratepayer advocates, and the general public as they each consider the ways in which utility resource planning can best serve the public interest.4 

# A n integrated resource plan, or IRP, is a utility plan for meeting forecasted annual peak and energy demand, plus some established reserve margin, through a combination of supply-side and demand-side resources over a specified future period. Steps taken in the creation of an IRP include:

• forecasting future loads,

• identifying potential resource options to meet those future loads,

• determining the optimal mix of resources based on the goal of minimizing future electric system costs,

• receiving and responding to public participation (where applicable), and

• creating and implementing the resource plan. Figure 1 shows these steps in a flow chart. 

# I. The Purpose and Use of Integrated Resource Planning

Integrated resource planning has many benefits to consumers, and other positive impacts on the environment. This is a planning process that, if correctly implemented, locates the lowest practical costs at which a utility can deliver reliable energy services to its customers. IRP differs from traditional planning in that it requires utilities to use analytical tools that are capable of fairly evaluating and comparing the costs and benefits of both demand- and supply-side resources. 2 The result is an opportunity to achieve lower overall costs than might result from considering only supply-side options. In particular, the inclusion of demand-side options presents more possibilities for saving fuel and reducing negative environmental impacts than might be possible if only supply-side options were considered. 3

**Figure 1**


### Flow Chart for Integrated Resource Planning 1

1 Hirst, E. A Good Integrated Resource Plan: Guidelines for Electric Utilities and Regulators. Oak Ridge National Laboratory. December 1992. Page 5. As it appears in Harrington, C., Moskovitz, D., Austin, T., Weinberg, C., & Holt, E. Integrated Resource Planning for State Utility Regulators. The Regulatory Assistance Project. June 1994.

2 Integrated Resource Planning for State Utility Regulators. Available at: http://www.raponline.org/document/ download/id/817

3 Kushler, M. & York, D. Utility Initia

tives: Integrated Resource Planning. July 2010. American Council for an Energy-Efficient Economy. Available at: http://aceee.org/policy-brief/util

ity-initiatives-integrated-resourceplanning Load Forecast

Identify Goals

Action Plans Existing Resources

Need for New Resources

Acquire Resources Define Suitable Resource Mixes Supply T & D Demand Rates

Monitor Uncertainty Analysis Public Review/ PUC Approval Social Environmental Factors5 4 Id footnote 2.

5 Hopper, C. & Goldman, N. Review of Utility Resource Plans in the West. Lawrence Berkeley National Laboratory. Presentation at the New Mexico PRC IRP Workshop, Santa Fe. June 8, 2006. Slide 17. In general, IRP focuses on minimizing customers’ bills rather than on rates—but an overall reduction in total resource cost achieved through the efficient use of energy will lower average energy bills. As a result, all customers benefit from the lower system costs that IRP achieves. 4 Alternatives examined by system planners in an IRP set

ting include adding generating capacity (thermal, renewable, customer-owned, or combined heat and power), adding transmission and distribution lines, and implementing ener

gy efficiency (EE) and demand response programs. Common risks that are addressed by scenario or sensitivity analyses

**Figure 2**


### States with Integrated Resource Planning or Similar Processes

Alabama Arizona Arkansas Colorado Delaware

Georgia Idaho

Illinois Indiana Iowa

Kansas Kentucky

Louisiana Maine

Maryland Minnesota

Mississippi Missouri Montana

Nebraska Nevada NH

MA

New Jersey

New Mexico New York

North Carolina North Dakota

Oklahoma Oregon

Rhode Island

South Carolina South Dakota

Tennessee Utah VT

CT

Virginia Washington

West Virginia Wyoming

Alaska

Hawaii California

Florida Michigan

Ohio Pennsylvania

Texas Wisconsin

State has an IRP rule and filing requirement
State is developing or revising an IRP rule and filing requirement State has a filing requirement for long-term plans
State does not have filing requirements for long-term plans in IRPs include fuel prices (coal, oil, and natural gas), load growth, electricity spot prices, variability of hydro resources, market structure, environmental regulations, and regulations on carbon dioxide (CO 2 ) and other emissions. 5 Resource planning requirements exist in many states, but may differ significantly from state to state. Utilities that create more than one resource plan in the same state may have different processes for creating those plans and may arrive at significantly different conclusions, despite being governed by the same regulations. Figure 2 shows the states that have IRP or long-term planning requirements. 6

6 For a complete list of the rules and regulations associated with integrated resource planning in the states, see Appendix 1.6 

# S tate IRP rules have been established in a number of ways. In certain states, legislatures have passed bills into law mandating that utilities engage in resource planning; in others, IRP rules have been codified under state administrative code. Some state utility commissions have adopted integrated resource planning regulations as part of their administrative rules, or have ordered it through docketed proceedings. Rules can also be developed through a combination of these processes. Various state IRP rules and their individual requirements are discussed in the sections below.


## A. IRP Planning Horizons Integrated resource plans are long-term in nature, but these planning periods vary according to state regulations. Table 1 lists the length of planning horizons typically found in IRP rules, as well as the states that have implemented 

# II. Examples of State Integrated Resource Planning Statutes and Regulations

**Table 1**



### Planning Horizons Found in IRP Rules

Planning Horizon
10 years

15 years

20 years

Multiple periods

Utility determined

Not specified Planning Horizon
Every two years

Every three years

Every four years

Every five years

Not specified States with Specified Planning Horizon
Arkansas, Delaware, Oklahoma, South Dakota, Wyoming

Arizona, Kentucky, Minnesota, North

Carolina, South Carolina, Virginia

Georgia, Hawaii, Idaho, Indiana, Louisiana, Missouri, Nebraska, Nevada,

New Mexico, North Dakota, Oregon, Utah, Vermont, Washington

Montana

Colorado

New Hampshire States with Specified Planning Horizon
Arizona, Delaware, Idaho, Indiana, Minnesota, Montana, New Hampshire, North Carolina, North Dakota, Oregon, South Dakota, Utah, Virginia, Washington

Arkansas, Georgia, Hawaii, Kentucky, Louisiana, Montana, Missouri, Nevada, New Mexico, Oklahoma, South Carolina, Vermont

Colorado

Nebraska

Wyoming these various planning horizons as a part of their rules. The most common planning horizon spans a 20 year period, with half of the IRP states mandating this planning period.


## B. Frequency of Updates Utility integrated resource plans must be updated periodically to reflect changing conditions with respect to load forecasts, fuel prices, capital costs, conditions in the electricity markets, environmental regulations, and other factors. IRP updates are typically required every two to three years, as shown in Table 2, below. Montana appears twice in Table 2, as traditional utilities are required to file IRPs every two years, while restructured utilities are required to file updates every three years. There are some exceptions to the typical update requirements of

**Table 2**


### Frequency of IRP Updates, as Determined by State Rules7 two to three years. Nebraska, for example, has a five year requirement for updates and is the only state to be made up entirely of public power utilities, many of which are custom

ers of the Western Area Power Administration (WAPA).Pursuant to the Energy Policy Act of 1992, municipallyowned utilities are required to prepare resource plans every five years, but do not have to make those plans publicly available. Most Nebraska utilities must comply with both WAPA IRP requirements as well as state IRP requirements.


## C. Resources Evaluated in Integrated Resource Planning Generally, state rules mandate that utilities consider all feasible supply-side, demand-side, and transmission resources that are expected to be available within the specified planning period. Many state IRP requirements make no specifications for resources that must be evaluated beyond this. Other states have gone into further detail about the resources that should be investigated, including:

• Delaware – utilities shall identify and evaluate all resource options, including: generation andtransmission service; supply contracts; short and longterm procurement from demand-side management (DSM), demand response (DR) and customer sited generation; resources that utilize new or innovative baseload technologies; resources that provide short or long-term environmental benefits; facilities that have existing fuel and transmission infrastructure; facilities that utilize existing brownfield or industrial sites; resources that promote fuel diversity; resources or facilities that support or improve reliability; and resources that encourage price stability. 7

• Indiana – utilities shall examine: all existing supply and demand-side resources and existing transmission; all potential new utility electric plant options and trans

mission facilities; all technologies and designs expected to be available within the twenty-year planning period, either on a commercial scale or demonstration scale; and a comprehensive array of demand side measures, including innovative rate design. 8

• Kentucky – utilities shall evaluate improvements inoperating efficiency of existing facilities, demandside programs, nonutility sources of generation, new power plants, transmission improvements, bulk power purchases and sales, and interconnections with other utilities. 9 There are state IRP rules that specify not only the resourc

es that must be evaluated, but also the amount of weight given to a particular resource by either the utilities or the Public Service/Utilities Commissions. Colorado is one such state, and is described in more detail in later sections. In almost all cases, state integrated resource planning rules have specific requirements for the planning horizons that should be covered, the frequency with which utility plans must be updated, and the generating resources that should be considered. Some states require nothing more, while others might also require, for example: 1) a certain number or a certain type of scenario analysis; 2) that certain types of resource cost tests be used to evaluate demand-side management policies; or 3) that externalities be considered by utilities when creating resource plans. Requirements for generating unit retirements and associated decommissioning costs are another example of something that some states might include in integrated resource planning rules, while others might not. The next section describes the discussion of this type of requirement in state IRP regulations.


## D. Retirements and Decommissioning Integrated resource planning is generally understood to be primarily concerned with the addition of resources in order to meet growing demand for electricity, and very few IRP rules mandate that utilities address end-of-life issues for generating units in their resource plans. In a summary document on integrated resource planning, the Regulatory Assistance Project states that “as utilities compare the cost of each supply- and demand-side option, they need to capture the entire life-cycle cost. This life-cycle cost means the fixed and variable costs incurred over the life of the investments: construction, operation, maintenance, and fuel costs.” 10 This description does not represent the full

7 HB 6, the Delaware Electric Utility Retail Customer Supply Act of 2006.

8 170 Indiana Administrative Code 4-7-1: Guidelines for Integrated Resource Planning by an Electric Utility.

9 Kentucky Administrative Regulation 807 KAR 5:058: Integrated resource planning by electric utilities.

10 Harrington, et al. Integrated Resource Planning for State Utility Regulators. The Regulatory Assistance Project. June 1994. Page 14.8 life of the investment, however, as it does not specifically include the costs associated with the retirement and decommissioning of a resource. State IRP rules and utility filings reflect this incomplete assessment of life-cycle costs. Twenty-seven states have IRP rules and 20 of them are silent with respect to unit retirements. Utah and Colorado require that utility filings include information about the life expectancies of the generating units in the resource plans. Three states – New Mexico, North Carolina, and South Dakota – are slightly more specific, and mandate that utilities provide expected retirement dates for generating facilities. Specifically, the utilities in each of the states are required to do the following:

• Utah – include the life expectancy of generating

resources

• Colorado – provide the estimated remaining useful lives of existing generation facilities without significant new investment or maintenance expense

• New Mexico – give the expected retirement dates for existing generating units

• North Carolina – provide a list of units to be retired from service (applies to both existing and planned generating facilities), with the location, capacity and expected date of retirement

• South Dakota – include those facilities to be removed from service during the planning period, along with the projected date of removal from service and the reason for removal There are only two state rules that make any mention of decommissioning costs:

• Arizona rules state that if the discontinuation, decommissioning, or mothballing of any power source or the permanent derating of any generating facility is expected, the utility must provide:
“i. Identification of each power source or generating unit involved,

ii. The costs and spending schedule for each discontinuation, decommissioning, mothballing, or derating, and

iii. The reasons for each discontinuation, decommissioning, mothballing, or derating.” 11

• Georgia laws and rules state that “Total cost estimates for proposed projects must include construction and non-construction related costs incurred through commercial operation, including decommissioning/ dismantlement costs.” 12 Rather than being addressed in utility integrated resource plans, generating unit retirements and associated decommissioning costs are largely left to be dealt with in other cases and proceedings that are brought before Public Utilities/Service Commissions.


## E. Long-term Procurement Planning RequirementsAs the electric industry began to restructure in the mid1990s, many states that had integrated resource planning requirements either repealed them with restructuring laws, or simply began to ignore them. Some states eventually replaced integrated resource planning laws with rules for resource procurement plans. A document designed to inform California’s 2010 Long-Term Procurement Plan (LTPP) requirement surveys the ways in which utilities in other states create their resource plans. The document states that “[w]hile California utilities have not undertaken a full integrated resource planning effort in many years, the 2010 LTPP proceeding is considering the appropriate role of utility resource planning in procuring the resources needed to meet state policy goals.” 13 Requirements for procurement plan filings differ from requirements for integrated resource plans. Planning periods are typically ten years, with some states requiring only a five year planning period. Procurement plans are usually required to be updated every year. Because utilities

11 Arizona Corporation Commission Decision No. 71722, in Docket No. RE-00000A-09-0249. June 3, 2010. Page 13. Amends Arizona Administrative Code Title 14, Chapter 2, Article 7, “Resource Planning.” Available at: http://images. edocket.azcc.gov/docketpdf/0000112475.pdf

12 Integrated Resource Planning Act of 1991 (O.C.G.A. § 46-3A-1), Amended. See also: Georgia Public Service Commission, General Rules, Integrated Resource Planning 515-3-4. Available at: http://rules.sos.state. ga.us/cgi-bin/page.cgi?g=GEORGIA_PUBLIC_SERVICE_ COMMISSION%2FGENERAL_RULES%2FINTEGRATED_ RESOURCE_PLANNING%2Findex.html&d=1

13 Aspen Environmental Group and Energy and Environmental Economics, Inc. Survey of Utility Resource Planning and Procurement Practices for Application to Long-Term Procurement Planning in California - DRAFT. Prepared for the California Public Utilities Commission. September 2008. Page 1.9 in these states operate in a deregulated market and do not own generation, procurement plans evaluate purchases for capacity and energy, as well as energy efficiency and other demand-side management programs. Connecticut is one such state that used to have an integrated resource planning requirement, and now has a requirement for procurement plans. The state had IRP regulations in place by the late 1980s, but this requirement was repealed when the restructuring law (Public Act 98-28) was passed in 1998. A long-term procurement planning law then became effective in 2007 (Public Act 07-242). Plans submitted to the Connecticut Energy Advisory Board in compliance with the 2007 law have much in common with utility IRPs and have even been called “Integrated Resource Plans,” though they are technically long-term procurement plans. The following section describes the ways in which IRP rules have been made in Arizona, Colorado, and Oregon, and presents some of the specifics of each of those rules.



### 1. Arizona The Arizona Corporation Commission (ACC) has been given both constitutional and statutory authority to oversee the operations of electric utilities, and to engage in rulemaking that includes the establishment of IRP regulations. Article 15 of the Arizona Constitution created the ACC, which oversees the operations of all public service corporations in the state, including investor-owned electric utilities. The Commission is given exclusive authority to establish rates, enact rules that are reasonably necessary in ratemaking, and determine what sort of regulation is reasonably necessary for effective ratemaking, 14 as established in Article 15, §3: The Corporation Commission shall have full power to, and shall, prescribe just and reasonable classifications to be used and just and reasonable rates and charges to be made and collected, by public service corporations within the State for service rendered therein, and make reasonable rules, regulations, and orders, by which such corporations shall be governed in the transaction of business within the State...and make and enforce reasonable rules, regulations, and orders for the convenience, comfort, and safety, and the preservation of the health, of the employees and patrons of such corporations... Utility practices in Arizona are not governed by legislation or by statute, but rather through administrative code created by rulemaking proceedings of the Arizona Corporation Commission. Renewable energy requirements, distributed energy resource requirements, and integrated resource planning reporting requirements have all been established in this way. The ACC has the authority to require that electric utilities provide reports concerning both past business activities and future plans. Integrated resource plans fall into this category. Article 15, §13 of the Arizona Constitution states that “[a]ll public service corporations... shall make such reports to the Corporation Commission, under oath, and provide such information concerning their acts and operations as may be required by law, or by the Corporation Commission.” Arizona Revised Statute §40- 204(A) expands on this requirement, stating that: Every public service corporation shall furnish to the Commission, in the form and detail the Commission prescribes, tabulations, computations, annual reports, monthly or periodical reports of earnings and expenses, and all other information required by it to carry into effect the provisions of this title and shall make specific answers to all questions submitted by the Commission. Regulating and requesting information regarding the resource portfolios of electric utilities is one way in which the ACC meets its constitutional and statutory obligations to ensure that just and reasonable rates are being charged to consumers of electricity. In this pursuit, the ACC adopted the state’s first Resource Planning and Procurement Rules in February 1989, requiring that utilities owning electric generation facilities file historical data every year, and 10-year resource plans every three years. The rules also provide for a Commission hearing to review these filings. In accordance with the rules, the first round of utility IRPs were filed in 1992 and hearings were held. In 1995, however, the Commission suspended the obligation of the electric utilities to file future resource plans until IRP rules could be modified to be consistent with impending electric industry competition and the passage of the retail electric competition rules. 15

14 Arizona Corporation Comm’n v. Woods, 171 Ariz. 286, 294 (“Woods”).

15 The Commission adopted retail electric competition rules in Decision No. 59943, dated December 26, 1996.10 In revising the IRP rules, Commission staff were required to hold workshops, open to all stakeholders and to the public, on specific resource planning topics. These workshops: Were to focus on developing needed infrastructure and a flexible, timely, and fair competitive procurement process; and were to consider whether and to what extent competitive procurement should include consideration of a diverse portfolio of purchased power, utility-owned generation, renewables, demand-side management, and distributed generation. 16 Following the workshops, a docket was opened for proposed rulemaking regarding resource planning, and on June 3, 2010 in Decision No. 71722, the Commission amended the Arizona Administrative Code Title 14, Chapter 2, Article 7, Resource Planning. In the most significant changes, compared to the original rules, the revised IRP rules: • Extend the forecasting and planning horizon from 10 years to 15 years;• Require submissions of utility IRPs every evennumbered year rather than every third year; • Require load-serving entities to include, in their IRP, data regarding air emissions, water consumption, and tons of coal ash produced; • Require that environmental impacts related to air emissions, solid waste, and other environmental factors and reduction of water consumption be analyzed and addressed in utility plans; • Require that plans address costs for compliance with current and projected environmental regulations; • Require that the resource plans include energy efficiency, to meet Commission-specified percentages; • Require that the resource plans include renewable resources, to meet the specified percentages in Arizona Administrative Code R14-2-1804; • Require that the resource plans include distributed energy resources, to meet the specified percentages in Arizona Administrative Code R14-2-1805; • Require that utilities submit a work plan in every odd year that outlines the upcoming 15-year resource plan, and lays out: 1) the utility’s method for assessing potential resources; 2) the sources of its current assumptions; and 3) a general outline of the procedures it will follow for public input, which includes an outline of the timing and extent of public participation and advisory group meetings that will be held before the resource plan is completed and filed. 17 Before they file the resource plan, utilities are required to provide an opportunity for public input. ACC practice also allows for public comment on the completed resource plan after it has been filed by the utility. In the revised rulemaking proceedings emphasis was placed on diversifying the resource base in utilities’ generation portfolios; on lowering costs through decreased reliance on volatile fossil-fuel based generation; and on considering and addressing environmental impacts, such as air emissions, coal ash, and water consumption. 18 Utilities must also submit a set of analyses to identify and assess the errors, risks, and uncertainties in: demand forecasts; the costs of DSM measures and power supply; the availability of sources of power; the costs of compliance with current and future environmental regulations; fuel prices and availability; construction costs, capital costs and operating costs; and any other factors the utility wishes to consider. This assessment should be done using sensitivity analysis and probabilistic modeling analysis. 19 The utility should provide a description of the ways in which these errors, risks, and uncertainties can be managed (e.g., by obtaining additional information, liming risk exposure, using incentives, creating additional options, incorporating flexibility, and participating in regional generation and transmission projects), along with a plan to do so. 20 Following the review of the utility IRP, the Commission is required to file an order that either acknowledges the resource plan (with or without amendment) or states the reasons for not acknowledging it. The first electric utility IRPs filed under the revised rules were submitted to the ACC in 2012. The filing from Arizona Public Service (APS) is discussed in later sections.

16 Arizona Corporation Commission. Decision No. 71722. Docket No. RE-00000A-09-0249. June 3, 2010.

17 Id.

18 Id. Page 12.

19 Arizona Corporation Commission. Decision No. 71722. Docket No. RE-00000A-09-0249. June 3, 2010. Exhibit A: Notice of Proposed Rulemaking. Page 42.

20 Id. Page 43.11 

### 2. Colorado Title 40 of the Colorado Revised Statutes establishes the state Public Utilities Commission and gives it authority to regulate the public utilities located within the state, specifically with regard to “the adequacy, installation, and extension of the power services and the facilities necessary to supply, extend, and connect the same.” 21 Title 40 also contains all of the legislative requirements with which Colorado’s public utilities must comply, and prescribes the general methods by which the PUC should evaluate compliance. The evaluation process is described in more detail in 4 Code of Colorado Regulations (CCR) 723-3: Rules Regulating Electric Utilities. This section of the code describes the rules promulgated by the Public Utilities Commission to establish the process for determining the need for additional electric resources by those electric utilities subject to the Commission’s jurisdiction, and for developing cost-effective resource portfolios to meet such need reliably. 22 The rules, in their current form, were adopted in 2003 and were referred to as least-cost planning rules. Beginning in 2003, utilities were required to file resource plans every four years, and may file an interim plan if changed circumstances justify the filing. Utilities may choose their own planning period, but that period must be at least 20 and no more than 40 years. Utilities may also specify the resource acquisition period they will follow, which will be between the first six and ten years of the planning period. The planning period is both the time frame for which the resource plan is developed, and the long-term period over which the net present value of revenue requirements is calculated. The resource acquisition period represents the near-term period in which the utility must actually acquire resources to meet system energy and demand requirements. For any resources they propose to acquire, utilities file needs assessments and draft requests for proposals (RFPs). The PUC may approve, deny, or order modifications to utility plans. Following PUC approval, utilities then begin the competitive bidding process to acquire the new resources needed to meet load and reserve requirements. Over the past decade, the PUC has opened several docketed proceedings and issued emergency rules revising the least-cost planning rules to provide specific guidelines for utilities, and to ensure compliance with new legislation adopted by Colorado state government. In Decision No. C07-0829 of September 19, 2007, the PUC adopted emergency rules modifying LCP rules as required by bills enacted in the 2006 and 2007 sessions of the Colorado Legislature. In general, these bills required the PUC to consider not only the costs of new generation resources as prescribed in least-cost planning rules, but also various benefits, requiring more technical expertise and involvement from the PUC in the resource selection

process. 23 Specifically, the following bills required the associated changes: • HB07-1037 establishes requirements for energy efficiency and demand-side management resources, and requires the PUC to shift from a least-cost planning standard to a more subjective consideration of multiple criteria “which will require substantially more Commission involvement in the resource selection process.” 24 The criteria shift applies to the evaluation of all resources, not only demand-side management (DSM) 25 measures. • HB07-1281 increases the renewable energy resources that electric utilities must acquire, necessitating greater integration between the resource planning rules and the new Renewable Energy Standards. • SB07-100 is intended to improve the economic viability of rural renewable resources. The bill provides for the designation of energy resource zones, and for the construction of transmission infrastructure to bring energy from these zones to load centers. • HB06-1281 requires the Commission “to give the fullest possible consideration to new clean and energy efficient technologies...(and) provides an

21 Colorado Revised Statutes 40-1-103.

22 4 Code of Colorado Regulations 723-3. Part 3: Rules Regulating Electric Utilities. Electric Resource Planning:
3601.

23 Colorado Public Utilities Commission. Decision No. C07- 0829. Docket No. 07R-0368E. September 19, 2007.

24 Id. Page 7.

25 Demand-side management , or DSM, measures involve reducing electricity use through activities or programs that promote electric energy efficiency or conservation, or more efficient management of electric energy loads.12 example of how the Commission can give such consideration to resources that may be in the public interest when accounting for the benefits of advancing the development of a particular resource, or when accounting for other benefits outside of a strict cost perspective.” 26 The statutory language describes some of those benefits: The Commission shall give the fullest possible consideration to the cost-effective implementation of new clean energy and energy-efficient technologies in its consideration of generation acquisitions for electric utilities, bearing in mind the beneficial contributions such technologies make to Colorado’s energy security, economic prosperity, environmental protection, and insulation from fuel price increases. The Commission shall consider utility investments in energy efficiency to be an acceptable use of ratepayer

moneys. 27 As a result of the various bills described above, the PUC chose to strike the term “least-cost” from the rules in all instances, changing their title to Resource Planning Rules. It also introduced the term cost-effective into the rules, defining it as “the reasonableness of costs and rate impacts in consideration of the benefits offered by new clean energy and energy-efficient technologies.” 28 These and other emergency rules were adopted on a permanent basis in Decision No. C07-1101 in Docket No. 07R-419E. Other significant changes to the Resource Planning Rules were adopted by the PUC in 2010 in response to the passage of HB10-1365, known as the Clean Air-Clean Jobs Act (CACJA). The legislative declaration of the Act states that: The general assembly hereby finds, determines, and declares that the federal “Clean Air Act,” 42 U.S.C. sec. 7401 et seq., will likely require reductions in emissions from coal-fired power plants operated by rate-regulated utilities in Colorado. A coordinated plan of emission reductions fromthese coal-fired power plants will enable Colorado rateregulated utilities to meet the requirements of the federal act and protect public health and the environment at a lower cost than a piecemeal approach. A coordinated plan of reduction of emissions for Colorado’s rate-regulated utilities will also result in reductions in many air pollutants and promote the use of natural gas and other low-emitting resources to meet Colorado’s electricity needs, which will in turn promote development of Colorado’s economy and industry. 29 The Act required that all utilities owning or operating coal-fired generating units in Colorado file an emissions reductions plan, which may include the following elements: emission control equipment, retirement of coal-fired units, conversion of coal units to natural gas, long-term fuel agreements, new natural gas pipelines, increased utilization of existing natural gas resources, and new transmission infrastructure. The CO Department of Public Health and the Environment and the PUC were tasked with reviewing the utility filings. Approval of the plans is contingent on several factors, including whether required emissions reductions would be achieved; whether the plan promotes economic development in the state; whether reliable electric service is preserved; and the degree to which the plan increases the utilization of natural gas or relies on energy efficiency or other low-emitting resources. Plans were to be filed by August 15, 2010, and full implementation is to occur by December 31, 2017. 30 While required emissions reduction plans were separate from Electric Resource Plans, the PUC opted to revise and clarify Electric Resource Planning (ERP) rules to make them more consistent with the CACJA. The PUC adopted revised rules on July 29, 2010 in Decision No. C10-0958 as part of Docket No. 10R-214E. Significant changes to the rules include: • Adoption as the policy of the state of Colorado that the PUC give the fullest possible consideration to the cost-effective implementation of new clean energy and energy-efficient technologies. • Inclusion in the resource plan of the annual water withdrawals and consumption for each new resource, and the water intensity of the generating system as a whole. • Inclusion of the projected emissions of sulfur dioxide, nitrogen oxides, particulate matter, mercury, and

26 Id. Page 9.

27 Colorado Revised Statutes 40-2-123(1)(a).

28 Colorado Public Utilities Commission. Decision No. C07- 0829. Docket No. 07R-0368E. September 19, 2007. Page 20.

29 Colorado Revised Statutes 40-3.2-203(1).

30 General Assembly of the State of Colorado. House Bill 10-
1365.13 31 Colorado Public Utilities Commission. Decision No. C10- 0958. Docket No. 10R-214E. July 29, 2010.

32 4 Code of Colorado Regulations 723-3. Part 3: Rules Regu

lating Electric Utilities. Electric Resource Planning: 3613(b).

33 4 Code of Colorado Regulations 723-3. Part 3: Rules Regu

lating Electric Utilities. Electric Resource Planning: 3613(e).

34 Public Utility Commission of Oregon. Order No. 89-507. Docket No. UM 180. April 20, 1989.

35 Id. Page 3.

36 Id. Page 7. carbon dioxide for new and existing generating

resources. • The Commission must consider the likelihood of new environmental regulations, and the risk of higher future costs associated with greenhouse gases, when it considers utility proposals. • Descriptions of at least three alternate resources plans that meet the same resource need as the base plan but include proportionally more renewable energy or demand-side resources. For the purpose of risk analysis, a range of possible future scenarios and input sensitivities should be proposed for testing the robustness of the alternative plans. • Permission for the utilities to implement cost-effective demand-side resources to reduce the need for additional resources that would otherwise need to be obtained through a competitive acquisition process. 31 Colorado’s IRP rules do not mandate public participation prior to the filing of the IRP. The rules are, however, unique in requiring that the utility, Commission staff, and the Office of Consumer Counsel agree upon an entity to act as an independent evaluator (paid for by the utility) and advisor to the Commission. The independent evaluator reviews all documents and data used by the utility in developing its resource plan, and submits a report to the Commission that contains its analysis of “whether the utility conducted a fair bid solicitation and bid evaluation process, with any deficiencies specifically reported.” 32 Following the filing of the utility’s resource plan, the IRP rules state that parties in the proceeding have 45 days to file comments on the plan and on the independent evaluator’s report. The utility has a chance to respond to comments, after which the Commission is required to issue a written decision approving, conditioning, modifying, or rejecting the utility’s preferred cost-effective resource plan, “which decision shall establish the final cost-effective resource plan.” 33 In 2011 the Colorado electric utilities filed the first electric resource plans that were consistent with these revised rules. The plan from Public Service Company of Colorado (“Public Service”) is discussed in section III of this report.



### 3. Oregon Oregon’s IRP rules are the most straightforward of the three states examined here. The state first established resource planning rules in 1989, in Public Utility Commission Order 89-507. The order directs all energy utilities in Oregon to undertake least-cost planning, which the Commission defines in a somewhat unique way, stating that: Least-cost planning differs from traditional planning in three major respects. It requires integration of supply and demand side options. It requires consideration of other than internal costs to the utility in determining what is least-cost. And it involves the Commission, the customers, and the public prior to the making of resource decisions rather than after the fact. ...Least-cost planning as mandated by this order will allow the public as well as the Commission to participate in the planning process at its earliest stages. 34 The PUC thus identifies one of the key procedural elements of least-cost planning as allowance for significant involvement from the public and other utilities in the preparation of the resource plan, which includes opportunities for the public to contribute information and ideas as well as to receive information. The Commission’s order states that “the open and collaborative character of least-cost planning may foster elevated confidence among those affected by the decisions and may make the process more responsive to demonstrated needs.” 35 Substantive elements of least-cost planning are similar to those found in other states, with the PUC emphasizing the evaluation of conservation in a manner that is consistent and comparable to that of supply-side resources, 36 and with the analysis of economic, environmental, and social uncertainties. The order also includes a concurring opinion from Commissioner Myron B. Katz, in which he discusses whether commissions, in the context of least-cost planning, should be interested in costs to utilities and ratepayers alone, or in overall costs to society. Katz suggests that utilities should seek to determine the costs for resources that include any externalities associated with those14resources, stating that “[a] resource should be deemed costeffective and thus eligible for selection if its costs are lower than the costs of alternative resources assuming a market in which all costs, including environmental costs, are reflected in resource price tags.” 37 Subsequent PUC Orders 07-002, 08-339, and 09-041 (which became O.A.R. 860-027-0400) updated planning guidelines and requirements, and changed least-cost planning terminology to integrated resource planning, in recognition of the fact that there are many risks and uncertainties associated with any portfolio that must be weighed, and that least-cost is not the only criterion for selecting the best resource portfolio. This emphasis on the importance of risk in integrated resource planning is one way in which Oregon differs from some other states. The emphasis is placed in the forefront of the revised rules, with Guideline 1(b) stating that “(r)isk and uncertainty must be considered.” 38 Risk is defined as a measure of the bad outcomes associated with a resource plan, while uncertainty is a measure of the quality of information about an event or outcome. Recognizing risks that are general to the electric industry and those that are specific to Oregon, the rules specify that, at a minimum, the following sources of risk must be considered in utility resource plans: load requirements, hydroelectric generation, plant forced outages, fuel prices, electricity prices, and costs to comply with any regulation of greenhouse gases, as well as any additional sources of risk and uncertainty. 39 In order to quantify these risks, utilities should calculate two different measures of the present value of revenue requirement risk (PVRR). The first should measure the variability of resulting PVRR costs under the different scenarios, and the second should measure the severity of any bad outcomes. 40 The primary goal of Oregon’s IRP planning process is thus “the selection of a portfolio of resources with the best combination of expected costs and associated risks and uncertainties for the utility and
its customers.” 41 A portfolio of resources with the lowest expected cost before the inclusion of various risks may in fact have higher costs than other resource portfolios once those risks are considered. The goal of the Oregon PUC in amending its rules was for utilities to identify the lowest-cost resource plan over the specified planning horizon by balancing both cost and risk. The Commission declines to mandate how the measures of PVRR risk be defined, instead leaving it up to 37 Id. Page 12.

38 Public Utility Commission of Oregon. Order No. 07-002. Docket No. UM 1056. January 8, 2007. Appendix A. Page 1.

39 Id.

40 Id. Appendix A. Page 2.

41 Id. Appendix A. Pages 1-2.

42 Id. Page 7.

43 From zero to $40 (1990$), as established in Order No. 93-695.

44 Public Utility Commission of Oregon. Order No. 07-002. Docket No. UM 1056. January 8, 2007.

45 Id. Page 8. the utilities and to “the interactive process of developing an IRP to make the best assessment of appropriate risk
measures.” 42 Unlike in Arizona, which requires that utilities create a plan to manage specific risks, Oregon requires that utilities take risks, their probabilities of occurrence, and the likelihood of bad outcomes into their choice of preferred resource plan. These subsequent orders make few other substantive changes to the rules established in order 89-507, but instead add detail on the information and analysis that the PUC wanted in order to acknowledge utility resource plans. Notable changes include: • The requirement that each utility ensure that a conservation potential study is done periodically for its entire service territory. • The requirement that demand response and distributed generation be evaluated similarly to more traditional supply-side resources. • The requirement that utilities include the expected regulatory compliance costs for various pollutants, that a range of potential CO 2 costs be analyzed, 43 and that sensitivity analyses be performed on a range of costs for nitrogen oxides, sulfur oxides, and mercury, if applicable. 44 Order 07-002 also details the nature of public involvement in the IRP process, stating that the public and other utilities should be allowed significant involvement in the preparation of an IRP—that they should be allowed to contribute information and ideas, and to make relevant inquiries of the utility formulating the plan. The utility should also make a draft IRP available for public review15 46 Id. Page 9.

47 Id. Page 2. and comment before filing a final version with the PUC. 45 Following submission of the integrated resource plan, intervening parties and Commission staff have six months to complete and file written comments on it. In advance of the deadline for written comments, the utility must also present the results of its resource plan to the Commission at a public meeting. The Commission then acknowledges the plan or returns it to the utility with comments. It may allow the utility to revise its resource plan before issuing an acknowledgement order. 46 The IRP rules are careful to point out that acknowledgement of the IRP does not guarantee favorable ratemaking treatment later on, but that the acknowledgement simply means the plan seemed reasonable at the time it was reviewed by the
Commission. 47 PacifiCorp, operating in Oregon as Pacific Power, is expected to file its 2013 IRP this year, but that plan was not available in time for inclusion in this paper. PacifiCorp’s 2011 IRP is discussed in later sections.16 48 Arizona Public Service. 2012 Integrated Resource Plan. March 2012. Page 2.

49 Id. Page 25.

50 Id. 

# III. Examples of Best Practices in Utility Integrated Resource Plans

A. Arizona Public Service 

# A rizona Public Service (APS) is the state’s largest electric utility, and has been serving retail and wholesale consumers since 1886. In March 2012, APS filed the first formal resource plan in 17 years with the Arizona Corporation Commission. This IRP was also the first to be filed under the ACC’s revised rules, as described in section II.A. From the time when the Corporation Commission issued the final IRP rules to the date that APS filed its resource plan, the utility was “engaging key stakeholders to gain an understanding and appreciate of their areas of concern.” 48 A series of workshops held during 2010 and 2011 sought to both inform and gather input from interested stakeholders on future resource decisions. The workshop topics included the resource fleet and transmission system; load forecasts; energy efficiency; smart grid; demand response; utility water consumption; fuel supplies and markets; technology options and costs; externalities; resource procurement; portfolios and sensitivities; and metrics and monetization costs for water, sulfur oxides, particulate matter, and nitrogen oxides. Approximately 35 to 50 stakeholders participated in each meeting, and several stakeholders were also invited to give presentations in some of the topic areas mentioned above. 49 APS also contracted with the Morrison Institute at Arizona State University to conduct a series of four “Informed Perception Project” surveys on customer preferences and concerns regarding the energy resource options available to APS. Results showed that APS customers “favored an increase in the use of renewable energy resources, such as solar and wind, and were interested in both the environmental impacts and reliability of energy choices.” 50 Over the course of the 15-year planning period, with the assumption that migration to the state and individual electricity consumption will return to historic highs, APS has forecast 3% average annual growth in nominal electricity requirements through 2027. Energy efficiency and distributed generation, in the form of rooftop solar installations, will help offset some of this growth, but APS expects that it will need to add additional conventional supply-side resources, in the form of natural gas-fired generation, in 2019. APS created four resource portfolios to evaluate: a base case, a “four corners contingency,” an “enhanced renewable” case, and a “coal retirement” case. Figure 3 shows the details of those plans. Each of the resource plans created by APS were analyzed using a production simulation model, PROMOD IV, which dispatches the energy resources in each of the portfolios and generates system costs, or the likely future revenue requirements, associated with each. Calculation of system revenue requirements demonstrated that the APS base case portfolio was the most cost-effective of the resource plans evaluated. APS also monitors specific metrics to provide a context for comparing and evaluating the portfolios. In addition to revenue requirements, those metrics include fuel diversity, capital expenditures, natural gas burn, water use, and CO 2 emissions. APS selected major cost inputs and evaluated several sensitivity scenarios, setting the assumptions for these variables higher and/or lower to test the impacts on the specific metrics being evaluated. These major cost inputs include natural gas prices, CO 2 prices, production and investment tax credits for renewable resources, energy efficiency costs, and monetization of SO 2 , NO

x , PM, and water. APS also created low-cost and high-cost scenarios,17 51 Id. Page 44. Arizona Public Service Company hired Black and Veatch Corporation to conduct a Solar Photovoltaic (PV) Integration Cost Study report that provides the company with an estimate for the incremental operating reserves necessary to integrate geographically diverse PV development in the APS service territory, and quantifies the anticipated incremental cost to provide the reserve capacity and energy services. “Solar Photovoltaic Integration Cost Study,” B&V Project No. 174880 (November 2012). Description

Nuclear

Coal

Natural Gas and Demand Response

Renewable Energy (RE) & Distributed Energy (DE)

Energy Efficiency (EE) Base Case (2012 Resource Plan)

Plan includes APS closing Four Corners units 1-3 and purchasing SCE’s share of

units 4-5; continues the current trajectory of EE

and RE compliance

1,146 MW 18.7%MWh

1,932 MW 26% MWh

7,424 MW 26.3% MWh

1,141 MW 13.7% MWh

1,525 MW 15.4% MWh Four Corners Contingency

Contingency plan depicting the retirement of the Four Corners coal-fired plant; energy replaced by additional natural gas

resources

1,146 MW 18.7% MWh

962 MW 12.7% MWh

8,394 MW 39.6% MWh

1,141 MW 13.7% MWh

1,525 MW 15.4% MWh Enhanced Renewable

Assumes 30% (after EE/DE) of energy needs met by renewable

resources; include the consummation of the
Four Corners transaction

1,146 MW 18.7% MWh

1,932 MW 26% MWh

7,138 MW 20.7%MWh

1,427 MW 22.8% MWh

1,525 MW 15.4% MWh Coal Retirement

Assumes APS retires all

coal-fired generation; energy replaced with a combination of natural

gas and renewable

resources

1,146 MW 18.7% MWh

0MW 0MWh

9,188 MW 46.3% MWh

1,308 MW 19.7% MWh

1,525 MW 15.4% MWh Resource Contributions (2027 Peak Capacity Contribution/ % Energy Mix)

which incorporate the low and high values for all of the variables mentioned above rather than testing them on an individual basis. The results of the sensitivity analysis showed that the four corners contingency and coal retirement portfolios have the most variability in terms of net present value of revenue requirements, which fluctuate 11-12% as compared to 6-7% for the base case and enhanced renewable portfolios. Natural gas price changes caused the largest impact on sensitivity results. Under the base case plan, APS achieves compliance with energy efficiency requirements and slightly exceeds compliance levels for renewable energy. Consistent with the intent of the revised rules, APS’s reliance on coal-fired generating resources drops by 12% between 2012 and 2027. Use of natural gas increases slightly over the course of the planning period under this scenario, but by 2027, no single fuel source makes up more than approximately 26% of the APS resource mix. Figure 4 shows the energy mix in 2027 compared to 2012 under the base case portfolio. **Figure 3:**



### Portfolios Considered in the APS 2012 IRP 51

APS had approximately 600 MW of excess capacity in 2012, heading into the summer peak. In the short term—over the next three years—the company planned to continue to pursue energy efficiency and renewable energy resources. During the intermediate term, years four to 15 of the planning period, APS plans to add 3,700 MW of natural gas capacity and 749 MW of renewable capacity. However, “[i]n the event that solar, wind, geothermal, or other renewable resources change in value and become a18 more viable and cost-effect option than natural gas, future resource plans may reflect a balance more commensurate to the enhanced renewable portfolio.” 53 APS should be commended for several elements of its 2012 IRP. The first of those is the comprehensive stakeholder process, which included workshops covering most, if not all, of the topic areas that are vital to comprehensive integrated resource plans. Not only were stakeholders invited to listen and offer feedback, they were also invited to present their points of view on a subset of these important issues. In the IRP itself, APS provides all non-confidential input and output data for stakeholder

review. Second, APS continues to pursue energy efficiency, renewable energy, and distributed generation resources in each of the resource portfolios it analyzed, meeting or exceeding ACC-specified goals and consistent with the Commission finding that: Continued reliance on fossil generation resources without the addition of renewable generation resources is inadequate and insufficient to promote and safeguard the security, 100

90

80

70

60

50

40

30

20

10

0 **Figure 4**



### Energy Mix Under The APS Base Case Portfolio 52

EE

RE & DE
Nuclear Gas
Coal 4.7% 4.9%

28.8%

23.7%

38.0% 15.4%

13.7%

18.7%

26.3%

26.0%

2012 2027

52 Id. Page 45.

53 Id. Page 64.

54 Arizona Public Service. 2012 Integrated Resource Plan. Page 13.

55 Id. Page 18. convenience, health, and safety of electric utilities’ customers and the Arizona public and is thus unjust, unreasonable, unsafe, and improper. 54 APS has also analyzed portfolios that meet the Commission goals of promoting fuel and technology diversity as the utility lowers its reliance on coal-fired generation and increases its use of energy efficiency and renewable energy resources. Third, APS takes environmental costs into account when evaluating its resource plans. The company uses a
CO 2 adder consistent with the assumption that federal regulation of CO 2 will occur within the 15-year planning period. In sensitivity scenarios, APS analyzes alternative prices for CO 2 emissions, and also includes adders for
SO 2 , NO

x , PM, and water. Emissions cost and water consumption are also two metrics by which APS evaluates its resource portfolios. Water in particular is a resource that has not been given much consideration in utility integrated resource planning in past decades, in this and in other jurisdictions—but it is especially important for Arizona and other states in the arid parts of the country, as it may at times act as a constraining resource on electric power generation. While APS has indeed done an admirable job in its 2012 Integrated Resource Plan, there are several areas in which the utility can still improve. The first is with respect to its load forecast. APS assumes a return to very high levels of load growth, at 3% per year for a total of 55% growth in energy consumption over the planning period. Load growth is one variable that can be highly uncertain. APS even states that “weather, population growth, economic trends, and energy consumptions behaviors are among the key variables that impact the Company’s view of future resource needs. Accurately forecasting any one of these variables over a 15-year period is a challenge. Accurately forecasting them all is impossible.” 5519 56 Id. Page 20.

57 Id. Page 18. Changes in the forecast can lead to significant changes in the quantity and type of resources needed in a utility’s portfolio. For this reason, utilities engaged in resource planning typically analyze sensitivity cases that use at least two (low and high) alternative load forecasts. APS admitted that “a challenge more specific to the APS service territory is load-growth uncertainty,” 56 and yet the company analyzed only a single load forecast—one that the company admits is more than triple the average growth of electricity demand in the United States. 57 The second improvement that APS could make to its IRP process relates to the creation of the utility’s resource portfolios. Often, in integrated resource planning, utilities will use resource optimization models—e.g., EGEAS, Strategist, or System Optimizer—to create resource portfolios. The user inputs data on peak and energy demand, reserve margins, fuel prices, emissions prices, capital and operating cost of both supply and demand resources, etc., and the optimization model will select the number and type of resources to be added over time to make up the least-cost plan. These models will also perform a simplified system dispatch in order to generate system revenue requirements over the planning period. Rather than using an optimization model to select the ideal resource portfolios, APS hand-selected the resource mix for each portfolio. Under this method, it is possible that a lower-cost resource plan exists that APS has not identified. This is particularly true in the sensitivity analyses that the company conducted. As described above, natural gas prices led to the greatest variance in system revenue requirements in the sensitivity analyses. Had an optimization model been used to evaluate scenarios with high natural gas prices, one might see the model select fewer natural gas-fired resources in favor of increased renewable or energy efficiency. Similarly, in sensitivity scenarios that look at decreased costs for energy efficiency, an optimization model might select additional quantities of energy efficiency to be added to the resource mix. Some of the supply-side resources selected using base EE costs might then not be required, as additional EE would lower both peak and energy demand. On page 104 of its IRP, APS presents a table of residential and non-residential EE programs that were rejected because program costs were higher than benefits. In sensitivity scenarios where lower EE costs were evaluated, some of these measures that were rejected may have met costeffectiveness tests and been selected for inclusion in utility resource portfolios.


## B. Public Service Company of Colorado The October 2011 IRP filing from Public Service Company of Colorado (“Public Service”) was filed shortlyafter the company’s filing that addressed the Clean AirClean Jobs Act. In the CACJA plan ultimately approved by the Colorado PUC, Public Service will retire 600 MW of base-load coal generation, fuel switch from coal to natural gas at another 450 MW of coal generation, and install emission controls at three other coal units by the year 2017. Additionally, as part of two separate filings, the company planned for the installation of 900 MW of additional wind and 30 MW of new solar by the end of 2012. These additions, repowerings, and retirements, along with the current weak growth in Colorado’s economy, led Public Service to project a resource need of only 292 MW of additional generation capacity by 2018. Public Service developed a “least-cost baseline case” resource portfolio, designed to meet resource needs during the Resource Acquisition Period from 2012 to 2018 at the lowest measurement of present value of revenue requirements. The utility also developed eight alternative plans that evaluate increasing amounts of renewable and distributed generation resources. These resource portfolios were evaluated using the Strategist model from the period of 2011-2050, and are shown in Figure 5. Public Service evaluated the baseline case and the eight alternative cases under several sensitivity scenarios, altering the price of CO 2 emissions, renewable tax incentives, natural gas prices, and level of sales. Figure 6 shows the results of the analysis for the first three variables. Public Service concludes from its analysis that existing and planned resources would be sufficient to meet the forecasted energy requirements of its system, but that natural gas-fired combustion turbines (CTs) would be required to provide the capacity necessary to maintain reserve margins. The company also concludes that adding20 **Figure 5**


### Least-Cost Baseline Case and Alternative Plans During the Resource Acquisition Period (RAP) From Public Service Company of Colorado’s 2011 IRP 58

**Figure 6**


### Sensitivity Results for Co 2 

### , Tax Incentives, and Gas Prices From Public Service Company of Colorado’s 2011 IRP 59 RAP Resource

Thermal Resources

Wind

Solar

Battery

Solar Thermal

Starting Assumptions

CO 2 3-Source Low Esc

CO 2 3-Source

CO 2 Early ($20 in 2017)

Low Gas

High Gas

PTC Wind

10% ITC Solar PV

30% ITC Solar Thermal 1 Baseline

2 CTs 346 MW A2 Wind

2 CTs 346 MW

200 MW

A2 Wind

$98

$9

$7

($36)

$164

$21

($97)

$98

$98 A3 PV

2 CTs 346 MW

200 MW

25 MW

A3 PV

$105

$10

$8

($38)

$179

$19

($90)

$119

$105 A4 Battery

2 CTs 346 MW

200 MW

25 MW

25 MW

A4 Battery

$160

$65

$62

$17

$238

$72

($35)

$174

$160 A5 Solar Thermal

2 CTs 346 MW

200 MW

25 MW

50 MW

A5 Solar Thermal

$298

$182

$178

$124

$393

$183

$103

$312

$235 B2 Wind

2 CTs 346 MW

800 MW

B2 Wind

$427

$75

$63

$117

$671

$151

$312

$427

$427 B3 PV

1 CT 173 MW

800 MW

100 MW

B3 PV

$489

$113

$101

$92

$760

$176

($251)

$546

$489 B4 Battery

1 CT 173 MW

800 MW

100 MW

100 MW

B4 Battery

$672

$297

$285

$98

$979

$369

($67)

$729

$672 B5 Solar Thermal

1 CT 173 MW

800 MW

100 MW

125 MW

B5 Solar Thermal

$881

$455

$441

$223

$1,204

$503

$142

$938

$741 Level A

Level ASensitivities Level B

Level B

Alternative Plan 2011-2050 PVRR Deltas from Baseline Case ($Millions)

58 Public Service Company of Colorado. 2011 Electric Resource Plan: Volume 1. October 31, 2011. Pp. 1-38. 59 Id. Pp. 1-41.21 renewable generating resources would increase system costs under both baseline and sensitivity assumptions. 60 The results of the sensitivity analysis shown in Figure 6 seem to indicate, however, that if the production tax credit (PTC) 61 for wind were to be extended, there would be some benefit to adding additional wind generation, as shown by the decline in present value of revenue requirements in this scenario relative to the base case. Given the results of the resource analysis, Public Service proposes to utilize a competitive All-Source Solicitation to acquire the resources needed to meet planning reservemargin targets. The solicitation would seek both shortterm and long-term power supply proposals, with a preference for short-term contracts. Public Service lists several uncertainties that it will face over the coming years: future environmental regulations, changing technology costs, tax credits that impact the relative costs of generation alternatives, fuel prices, and economic growth in its service territory. 62 Given these uncertainties and the relatively small resource need, the shorter-term power urchase agreements would allow the utility to wait and see if and how uncertainties can be resolved before adding new generation facilities to its resource mix. The company will also offer enough self-build power supply proposals into the solicitation process to meet the needs over the resource acquisition period. These proposals would ensure that at least one portfolio could be developed with company-owned facilities, and that generating capacity will be expanded at existing sites. Public Service requests that the PUC allow it to conduct periodic solicitations for additional renewable energy, if and when markets become most favorable to customers; but it reports no plans to add additional renewables over the acquisition period. The company states that, “[t]o the extent the Commission desires to see portfolios from the Phase 2 process that contain increasing levels of renewable or Section 123 Resources the Commission should direct the Company to do so in its Phase 1 order.” 63 Public Service’s 2011 IRP is comprehensive, thorough, and a good example of effective resource planning. Resource planning in Colorado is driven by: 1) the state Legislature, as statutes dictate the content of state IRP rules; 2) by interveners, whose comments and suggestions during IRP processes can lead to changes in both rules and content of utility resource plans; and 3) by the PUC, which oversees the process and may require that utilities revise resource 60 Id. Pp. 1-43.

61 The federal renewable energy production tax credit (PTC) provides a per-kilowatt-hour tax credit for electricity generating by various types of renewable energy resources and sold by the taxpayer to an unrelated person during the taxable year. The PTC was originally enacted in 1992 and has been extended several times, most recently in January 2013 as part of the American Taxpayer Relief Act of 2012 (H.R. 6, Sec 407). Currently, the PTC for wind resources for which construction began prior to December 31, 2013 is 2.3 cents/ kWh.

62 Id. Pp. 1-5.

63 Id. Pp. 1-49.

64 Id. Pp. 1-59. plans in specific ways prior to receiving Commission approval. The input and oversight from these three entities, combined with the utilities’ expertise, leads to the inclusion of several notable elements in the resource plan that demonstrate additional issues of concern in Colorado. First, recognizing that acquiring necessary resources does not always go according to plan, the utility creates and describes a series of the more common contingency events—e.g., bidders withdrawing proposals, transmission development delays, higher than anticipated electric demand, etc.—and develops plans to address them if they

occur. 64 Second, Public Service acknowledges that its planned volume of wind installations (2,100 MW by 2012) creates specific challenges and requirements that much lower volumes of renewables would not. Because wind output can be variable and uncertain, there may be additional flexibility requirements on an electric system—i.e., there must be a certain amount of generation that can be brought on-line within a 30-minute period in order to respond to changes in renewable output. Public Service conducts an assessment of the need for flexible resources in its IRP’s general assessment of need. Flexibility studies are not a part of traditional integrated resource planning, but Public Service is responding to unique circumstances in its service territory by incorporating this type of study in its resource planning. Utilities sometimes cite the variability and uncertainty of wind and other renewables as reasons not to pursue these types of resources in their portfolios; Public Service shows,22 65 Chupka, M,, Murphy, D. & Newell, S. Reviving Integrated Resource Planning for Electric Utilities: New Challenges and Innovative Approaches. Brattle Group. 2008. Page 2.

66 Public Service Company of Colorado. 2011 Electric Resource Plan: Volume 1. October 31, 2011. Pp. 1-5.

67 Wyoming does not have its own IRP obligation, but instead mandates that any utility serving in the state that is required to submit an IRP in another jurisdiction also file that IRP with the Wyoming PSC.

68 Id. Page 8. however, that these challenges can be planned for in a reasonable way and are not a reason to avoid renewable additions. Finally, traditional integrated resource planning does not pursue short-term strategies, such as market purchases that may buy time in the hope that some uncertainties will be resolved.” 65 The Public Service IRP does just that, however, by making shorter-term resource acquisition decisions and preserving “decisions involving new generation facilities to a point in the future when we see how these uncertainties are resolved.” 66 While Public Service should be applauded for its integration of renewables to date, it is unclear from the company’s IRP whether it truly views renewable generating technologies as a system resource as opposed to an obligation established by the state legislature and the PUC. As mentioned above, Public Service has no plans to pursue additional renewable acquisitions during the next seven years, even though sensitivity analyses show that additional wind generation may be beneficial to ratepayers if the production tax credit were to be extended. The company does ask that it be granted permission to conduct solicitations for renewables outside of the resource planning process if it determines that market conditions are “favorable,” but it gives no indication as to what favorable market conditions might look like. An evaluation of the market conditions favorable to renewables would be very helpful in the context of resource planning, and could be included in future IRPs or updates from Public Service.


## C. PacifiCorp Of the three utilities examined here, PacifiCorp is unique in that it operates across six states—Oregon, Washington, California, Idaho, Utah, and Wyoming, five of which have IRP or other long-term planning requirements. 67 This gives PacifiCorp the additional challenge of planning ona system-wide basis while meeting each of the resourceacquisition mandates and policies in the states where it operates. The company evaluates a 20-year study period, but focuses on the first ten years (2011-2020) in its assessment of resource need. In that ten-year planning period, PacifiCorp forecasts that system peak load will grow at 2.1% per year (2.4% for

Capacity (MW)

Resource 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 Total

CCCT F Class

- - - 625

- 597

- - - - 1,222

CCCT H Class

- - - - - - - - 475

- 475 Coal Plan Turbine Upgrades 12 19 6

- - 18

- 8

- - 63 Wind, Wyoming

- - - - - - - 300 300 200 800

CHP-Biomass 5 5 5 5 5 5 5 5 5 5 50 DSM, Class 1 6 70 57 20 97

- - - - - 250 DSM, Class 2 108 114 110 118 122 124 126 120 122 125 1,189 Oregon Solar Programs 4 4 4 3 3

- - - - - 18 Micro Solar – Water Heating

- 4 4 4 4 4 4 4

- - 28

Firm Market Purchases 350 1,240 1,429 1,190 1,149 775 822 967 695 995 N/A **Figure 7**


### Resource Additions in the Preferred Portfolio—PacifiCorp’s 2011 IRP 6823 69 PacifiCorp. 2011 Integrated Resource Plan: Volume 1. March 31, 2011. Page 83.

70 Id. Page 10.

71 Id. Page 13. the eastern system peak and 1.4% for the western system peak), and that energy requirements will grow by 1.8% per year. Resource deficits will begin in the first year, with PacifiCorp being short 326 MW in 2011. This deficit grows to 3,852 MW by 2020. In the near-term, shortages will be met with DSM, renewables, and market purchases, but new baseload and intermediate generating units begin to be added to the resource mix in 2014. 69 Figure 7 shows the proposed resource additions. If PacifiCorp were to proceed with these proposed resource additions, by 2020 its capacity mix would be as shown in Figure 8. In this scenario, traditional thermal resources still make up two-thirds of PacifiCorp’s capacity mix; DSM makes up just over 13%, and renewables make up 2.6%. As Figure 9 shows, PacifiCorp’s energy mix looks slightly different under its preferred portfolio. The percentage of total energy generated from coal-fired resources drops by 26% between 2011 and 2020, while the amount of

100

90

80

70

60

50

40

30

20

10

0 100

90

80

70

60

50

40

30

20

10

0

**Figure 8**


### Capacity Mix Under the PacifiCorp Preferred Portfolio 70 **Figure 9**


### Energy Mix Under the PacifiCorp Preferred Portfolio 71

Class 1 DSM

CHP & Other

Front Office Transactions Hydroelectric

Class 2 DSM

Class 1 DSM

CHP & Other

Front Office Transactions Hydroelectric

Class 2 DSM 47.5% 62.5%

18.3% 11.5% 11.7%

40.4% 36.3%

26.4% 25.5%

7.4%

2.4% 10.7% 0.1% 0.9%

2.6% 7.4% 0.1% 0.1%

6.5% 3.2%

5.4% 1.5%

3.2% 5.2%

9.3% 8.1%

5.0% 7.1%

4.7% 7.8%

8.2% 11.2% 0.9%

2011 2011

2020 2020

Existing Purchases

Renewables

Gas

Coal

Existing Purchases

Renewables

Gas

Coal energy from gas-fired resources more than doubles. Even with the significant drop in generation from coal, energy from thermal resources makes up 61% of PacifiCorp’s total energy. DSM makes up 11% of the energy mix, with another 11% coming from renewable resources. Hydroelectric power and energy purchases make up the bulk of the remaining energy. Of the three utilities examined in this report, PacifiCorp’s portfolio modeling process is the most comprehensive. It uses a model called System Optimizer, which has the capability to determine capacity expansion plans, to run a production cost simulation of each optimized portfolio, and to perform a risk assessment on these portfolios. 0.1% 0.3%

0.8%24 Altogether, PacifiCorp defined 67 input scenarios for portfolio development. These looked at alternative transmission configurations, CO 2 price levels and regulation types, natural gas prices, and renewable resource policies. Sensitivity cases examined additional incremental costs for coal plants, alternative load forecasts, renewable generation costs and incentives, and DSM resource availability. Top resource portfolios were determined on the basis of the combination of lowest average portfolio cost and worst-case portfolio cost resulting from 100 simulation runs. Final portfolios were selected after considering such

**Figure 10**


### Pacificorp Modeling and Risk Analysis Process 73 criteria as risk-adjusted portfolio cost, 10-year customer rate impact, CO 2 emissions, supply reliability, resource diversity, and uncertainty and risk surrounding greenhouse gas and RPS policies. 72 Figure 10 shows PacifiCorp’s schematic of its modeling process. PacifiCorp is one of the only utilities in thecountry that models energy efficiency resources as supplyside resources, rather than as load modifiers. The utility provides the model with specific quantities of energy efficiency at given costs, and allows those efficiency resources to compete against the other resources from

Phase 1: Case Definition

Phase 2: Price Forecast Development Phase 3: Optimized Portfolio Development

Phase 4: Monte Carlo Production Cost Simulation Phase 5: Top-performing Portfolio Selection

Phase 6: Deterministic Risk Assessment

Phase 7: Preferred Portfolio Selection/Acquisition Risk Analysis Optimized Resource Portfolios Final Screen

Electricity prices Gas prices Emission prices Planning and Risk Model Runs (Three CO 2 scenario runs per portfolio) System Optimizer Runs (Least-cost dispatch with fixed resources for each set of case assumptions)

System Optimizer Runs (Procurement scenarios) System Optimizer Runs Initial Screen Efficient Frontier Portfolios

CO 2 Cost Assumptions Gas Prices

IPM model runs (National)

CO 2 cost responses: Gas basis differentials and SO 2 prices

MIDAS model runs (Western) CO 2 tax scenarios ($/ton, 2015-2030): None, $0, Medium, $20 to $62, Low to Very High $12 to $95

Stochastic costs, risk, and supply reliability

measures Core case subset

Portfolio cost for each case Core Cases

Sensitivity

Cases

72 Id. Page 153. 73 Id. Page 155.25 74 Lamont, D. & Gerhard, J. The Treatment of Energy Efficiency in Integrated Resource Plans: A Review of Six State Practices. Regulatory Assistance Project. January 2013. Pp. 6-8.

75 Sierra Club’s Preliminary Comments in the Matter of PacifiCorp 2011 Integrated Resource Plan before the Public Utility Commission of Oregon. LC 52. August 25, 2011.

76 Opening Comments of the Citizens’ Utility Board of Oregon in the Matter of PacifiCorp 2011 Integrated Resource Plan before the Public Utility Commission of Oregon. LC 52. which the model is able to select. PacifiCorp’s efficiency resource information in its 2011 IRP is based on a 2010 energy efficiency potential study that provided an estimateof the size, type, timing, location, and cost of the demandside resources that are technically available in PacifiCorp’s service territory. Data for more than 18,000 measures were available after the resources were separated by customer segment, facility type, and unique EE measures. Energy efficiency measures are called Class 2 DSM, while capacity-based measures are separated into twocategories: Class 1 DSM includes dispatchable demandresponse programs, and Class 3 DSM includes pricing programs. Focusing on Class 2 DSM measures, PacifiCorp consolidated them into nine cost bundles grouped by levelized cost for inclusion in the modeling, and 1,400 supply curves were modeled for the IRP. 74 Energy efficiency measures performed well in the modeling, representing the largest resource added through 2030 across all portfolios with cumulative capacity additions exceeding 2,500 MW in the preferred portfolio. The inclusion of such large quantities of energy efficiency creates huge cost savings to ratepayers. If energy efficiency were not included in PacifiCorp’s resource portfolio, the utility would have to meet electric load by adding 2,500 MW of supply-side resources at much greater cost. Although PacifiCorp’s portfolio modeling process is comprehensive and well-executed, system resource modeling in general is only as good as the input assumptions used to generate the portfolios. The most significant area in need of improvement in the PacifiCorp IRP process relates to the input assumptions and analysis regarding the company’s coal fleet—or, rather, the lack of analysis presented on this in the IRP. This lack of analysis began during the stakeholder process. In comments that it submitted, the Sierra Club states that it actively participated in the stakeholder input process, and raised many of the issues discussed in those comments. “The company did not respond to any requests for data related to the topics addressed in these comments, choosing instead to provide only a small amount of materials in the final draft, just days before the company submitted the final IRP.” 75 PacifiCorp’s 26 coal-fired boilers make up almost two thirds of its generation. To keep these units running while meeting stricter federal air pollution standards, the company would have to spend $1.57 billion in environmental capital cost from 2011 to 2020, in addition to $1.2 billion that it invested before 2011. Operating costs would raise the total cost to customers to $4.2 billion, or $360 million on an annual basis by 2030. 76 PacifiCorp, however, makes no mention of these current compliance obligations or any future costs in the 2011 IRP or its appendices. The utility failed to disclose the costs that would be faced by its coal fleet in its 2011 IRP, and failed to do a comprehensive analysis of the economics of each of its coal-fired generating units. Absent this analysis, the resource portfolios analyzed by the company cannot be considered to be truly “optimized.” It is highly likely that PacifiCorp could add additional renewable resources to its portfolio. As discussed above, Public Service Company of Colorado had 2,100 MW of wind capacity alone on its system at the end of 2012, and they are a single utility operating in one state. PacifiCorp’s territory covers portions of six states, many with large amounts of renewable potential. PacifiCorp’s service territory also borders other states with large amounts of renewable potential, and the company could enter into long-term contracts for renewable energy. The company states in the IRP that it commissioned a study on geothermal potential, yet its resource portfolio does not include any anticipated geothermal energy or capacity during the study period.26 77 Arkansas Public Service Commission. Resource Planning Guidelines for Electric Utilities. June 2007. 

# IV. Recommendations for Prudent Integrated Resource Planning 

# P rudent integrated resource planning involves both the process of creating and sharing the resource plan with stakeholders, and the elements that are analyzed and included in the plan itself. This section provides recommendations, for both the IRP process and the resulting resource plan, that are designed to result in responsible and comprehensive utility integrated resource plans.


## A. Integrated Resource Planning Process Integrated resource planning processes differ from state to state. The ideal process begins with the determination of the IRP guidelines or rules. Integrated resource planning rules were first established in many states in the late 1980s or early 1990s; Oregon’s first rules, for example, were established by PUC order in 1989. Significant changes have occurred since then. During the mid- to late 1990s, electric restructuring moved many utilities away from traditional resource planning in favor of market-based provision of electric supply; and today, climate change, national security, and volatility in fuel and commodity markets can make it difficult to determine the best way in which to supply electricity to consumers. Integrated resource planning rules should thus be reexamined periodically, to make sure they reflect the current conditions and challenges associated with providing reliable electric service at reasonable costs. Arizona began the process of changing its rules after retail competition was instituted in the state by the Corporation Commission—and although the rules took over a decade to be revised and put into effect, the current regulations have been designed to address the issues that are of concern today. When IRP rules are reexamined, state commissions should open proceedings that are open to the public, and stakeholders should be allowed to offer input on the ways in which rules should be revised, as well as to review and comment on any draft documents that are issued. All three of the state IRP rules examined here have gone through this process, and in drafting revised rules, each of the state commissions carefully considered the feedback offered by interveners and adopted recommendations from both public interest groups and utilities.



### 1. Resource Plan Development Stakeholder group involvement is equally important when it is time for a utility to develop its integrated resource plan. As was discussed in section III.A., APS detailed its stakeholder process in its 2012 IRP. During the two-year period that preceded the filing of the plan, the utility held various workshops where stakeholders received updates on the inputs to be used, and were able to offer feedback and even give presentations on these various inputs. Stakeholders were also surveyed to determine their preferences with regard to the energy resources selected by APS. Not only does this stakeholder process inform the content of the resource plan that is ultimately filed by the utility; it can also help to inform the review process once the filing has been made. Other states have also recognized the benefits of stakeholder involvement in IRP and developed model processes. In its Resource Planning Guidelines for Electric Utilities, the Arkansas Public Service Commission suggests that utilities establish a Stakeholder Committee to assist in preparing resource plans that “should be broadly representative of retail and wholesale customers, independent power suppliers, marketers, and other interested entities in the service area.” 77 The members of this committee would review utility objectives, assumptions, and estimated needs early in the planning cycle, and would submit a report along with the utility’s resource plan. Committee members may also submit additional comments to the Commission, which may27 78 Id.

79 Public Utilities Commission, State of Hawaii. A Framework for Integrated Resource Planning. Revised May 22, 1992.

80 807 KAR 5:058. Integrated Resource Planning by Electric Utilities.

81 Colorado Public Utilities Commission. Decision No. C11- 0442. Docket No. 10A-554EG. March 30, 2011.

82 The Treatment of Energy Efficiency in Integrated Resource Plans

. Page 15. require the utility to re-evaluate its plan to address these

comments. 78 In Hawaii, IRP rules were designed to attempt to maximize public participation in the planning process. In each county within its service territory, the utility is required to organize advisory groups made up of representatives of public and private entities whose interests are affected by the utility’s resource plan—including state and county agencies and environmental, cultural, business, and community interest groups. The rules specify that “(a)n advisory group should be representative of as broad a spectrum of interests as possible.” 79 Whether required by IRP rules or not, it is good practice for a utility to convene a stakeholder group, or to hold public meetings that are open to all interested parties, before creating and submitting its resource plan. These meetings are useful both to provide information and invite feedback on the input assumptions and the process that the utility is using in its resource planning, and to help ensure that the resulting plan is relevant and reflects the interests of ratepayers and the general public.



### 2. Resource Plan Review Many state utility commissions are quasi-judicial boards that rely on the rules of civil procedure and allow for participation and intervention from different organizations and members of the public (provided they have standing in the proceeding, or an ability to assist the commission in making decisions). After a utility has filed its resource plan, the state PUC should open a proceeding that allows stakeholders to review and submit written comments on the filing. This feedback should be taken into account during the review by the PUC and its staff. Commissions should take an active role in assessing the validity of the inputs used by the utilities in their filings, the resulting outcomes, and whether these are consistent with both the IRP rules and the state’s energy policies and goals. In Kentucky, for example, the IRP rules specify that once a utility’s IRP has been received, the Commission should develop a procedural schedule allowing for submission of written interrogatories to the utility by commission staff and any interveners, written comments by staff and interveners, and responses to these interrogatories and comments by the utility. The Commission may convene conferences to discuss the filed IRP if it wishes to do so. Following a review of the plan and intervener comments, Commission staff will issue a report summarizing its review and offering recommendations to the utility for subsequent IRP filings. 80 Of the states examined in this report, the Colorado PUC has taken on a particularly active role in determining whether utility resource choices were in the public interest. The PUC did so, for example, in its review of Public Service Company of Colorado’s 2010 DSM Plan, when it rejected the energy efficiency goals proposed by the company and instead asked that the utility adopt goals recommended by an intervener—the Southwest Energy Efficiency Project— that were approximately 130% of the goals in place at the

time. 81 These EE goals were then incorporated into the 2011 IRP, in the calculation of resource need as one of the input modeling assumptions. 82 Many states, though not all, require that utility plans be available to interveners and/or members of the public for review and participation in resource planning dockets. This signals to both stakeholders and utilities that the IRP process should be collaborative, and that stakeholders can and do offer valuable insights and opinions into resource planning that should be taken into account by utilities when developing their plans. Active oversight and participation by the state PUC is critical to ensuring that comments and proposals by interveners are reviewed, considered fully, and incorporated into utility resource plans when reasonable.28 83 State and Local Energy Efficiency Action Network. UsingIntegrated Resource Planning to Encourage Investment in CostEffective Energy Efficiency Measures. September 2011. Page 5.

84 Public Service Company of Colorado. 2011 Electric Resource Plan: Volume 1. October 31, 2011. Pp. 1-5.

85 Biewald, B. & Bernow, S. Electric Utility System Reliability Analysis: Determining the Need for Generating Capacity. Boston: Energy Systems Research Group. 1988. 

## B. Integrated Resource Plans A good electric system IRP should include, at a

minimum:

Load forecast A company’s load forecast (annual peak and energy) is one of the major determinants of the quantity and type of resources that must be added in a utility’s service territory over a given time period, and has always been the starting point for resource planning. Projections of future load should be based on realistic assumptions about local population changes and local economic factors 83 and should be fully documented. Resource needs can rise or falldramatically over a short period of time, and frequent, upto-date load forecasts are necessary for utilities to be able to adequately assess the quantity and type of additional resources that might be needed in a specific planning period. In Colorado, for example, at the time of Public Service’s CACJA filing in mid-2010, the company was projecting a resource need of approximately 1,000 MW by 2018. At the time of its IRP filing in October 2011, the projection of resource need had dropped to 292 MW as a result of the economic recession and the success of DSM and solar

programs. 84 In order to help plan for any future changes in load, utilities should model a range of possible load forecasts, not just a reference case.

Reserves and reliability Reliability is typically defined as having capacity equal to the forecasted peak demand, plus a reserve margin during the hours in which that peak demand is expected to occur. Reserve requirements should provide for adequate capacity based on a rigorous analysis of system characteristics and proper treatment of intermittent resources. The system characteristics affecting reliability and reserve requirements include load shape, generating unit forced-outage rates, generating unit maintenance-outage requirements, number and size of the generating units in a region or service territory, transmission interties with neighboring utilities, and availability and effectiveness of intervention procedures. 85

Demand-Side Management Many state IRP statutes or regulations include in the definition of integrated resource planning an evaluation of energy conservation and efficiency. Even so, “[w]hile demand-side resources have always been a conceptual part of IRP, in practice they have not always been an important focus.” 86, 87 As generation from traditional supply-side resources is growing more costly and energy efficiencymeasures are becoming less expensive, however, demandside alternatives have gained a greater number of advocates across the United States.Not only is energy efficiency often the lowestcost resource available to system planners, it can also mitigate a variety of risks, such as that of impending carbon legislation and other environmental regulations affecting air and water quality. In addition to offsetting energy consumption, implementing EE measures can lead to a deferral in costly transmission and distribution

investments. 88 In the IRPs of most utilities, demand-side resources are included only up to the point that statutory goals are met, or mandatory levels of investment are included. Resource planners often incorporate the effects of those demand-side policies as adjustments (“decrements”) to their forecasts of future load requirements. However,

86 Chupka, M., Murphy D. & Newell, S. Reviving Integrated Resource Planning for Electric Utilities: New Challenges and Innovative Approaches. Brattle Group. 2008. Page 3.

87 Demand response, which is another type of demand-side resource, is considered in utility IRPs even less frequently than is efficiency. A full discussion of how demand response is included or excluded in IRPs is beyond the scope of this report.

88 The Treatment of Energy Efficiency in Integrated Resource Plans. Page 15.29 89 State and Local Energy Efficiency Action Network. Using Integrated Resource Planning to Encourage Investment in Cost-Effective Energy Efficiency Measures. September 2011. Page 6.

90 Arizona Public Service. 2012 Integrated Resource Plan. March 2012. Page 36.

91 Arizona Corporation Commission. Decision No. 71819. Docket No. RE-00000C-09-0427. August 10, 2010.

92 Chapter 19.285 of the Revised Code of Washington (RCW): Energy Independence Act.

93 The Northwest Power and Conservation Council (NWPCC) is a regional entity that helps the states in the Pacific

“The best IRPs create levelized cost curves for demand-side resources that are comparable to the levelized cost curves for supply-side resources. ... By developing cost curves for demand-side options, planners allow the model to choose an optimum level of investment. So if demand-side resources can meet customer demand for less cost than supply-side resources, as is frequently the case, this approach may result in more than the minimum investment levels required under other policies.” 89 The three integrated resource plans discussed in this report each deal with energy efficiency in different ways. InArizona, the Corporation Commission has set a demandside management standard, and each of the portfolios analyzed in the IRP from Arizona Public Service assume full compliance with that standard. 90 Public utilities are required to achieve annual energy savings of at least 22% by 2020, and savings (measured as a percent of retail energy sales) should increase incrementally in each calendar year prior to 2020. 91 In its IRP, APS has calculated the number of MWh of energy savings needed to be compliant with Commission standards, and has imported these targets into the IRP as a load decrement over the planning horizon. Colorado’s Energy Efficiency Resource Standard (EERS) was established by Colorado House Bill 07-1037 and codified under the Code of Colorado Regulations §40-3.2- 104. The law requires that the Colorado Commission set savings goals for energy and peak demand for the state’s investor-owned utilities, but specifies minimum savings goals of at least 5% of both retail energy sales and peak demand from a 2006 baseline. Utilities are required to submit DSM plans, which are then reviewed and approved by the Commision, or approved with modifications. The plan that is ultimately approved may require levels of DSM that are higher than the minimum savings goals that have previously been established. Similar to APS, in its mostrecent IRP, Public Service took the most recent utilityspecific DSM goals approved by the Commission and imported them into the IRP process as a load decrement, reducing the resource need over the planning period. PacifiCorp is subject to EERS requirements in Washington and California. In 2006 in Washington, voters passed Initiative 937, which requires that electric utilities serving more than 25,000 customers undertake all cost-effective energy conservation. Beginning in 2010,utilities must do an assessment of all the achievable costeffective conservation potential in even-numbered years. 92 Alternatively, efficiency targets may be based on a utility’s most recent integrated resource plan, provided that plan is consistent with the resource plan for the Northwest Power and Conservation Council. 93 California Assembly Bill 2021, enacted in 2006, called for a 10% reduction in electricity consumption within 10 years. It also required that the California Energy Commission (CEC), California Public Utilities Commission (CPUC), and other interested parties develop a statewide estimate of all cost-effective electricity savings, develop efficiency and demand reduction targets for the next 10 years, and update the study every three years. Goals were developed by the CPUC in 2008 for years 2012 through 2020, and each of the three investor-owned utilities in the state has distinct requirements for electricity savings and demand reduction. 94

Northwest ensure an affordable and reliable energy system while maintaining fish and wildlife health in the Columbia River Basin. One responsibility of the NWPCC is to publish a 20-year electric plan that serves as a guide for Bonneville Power and its customer utilities in the region. The regional plan drives best practices in energy efficiency and is a reference against which utility plans may be measured. In the Sixth Power Plan, published in 2010, the NWPCC recommended that energy efficiency be deployed aggressively such that it meets 85% of new demand for electricity over the next 20 years.

94 California Public Utilities Commission. Decision 08-07-047. Rulemaking 06-04-010. July 31, 2008.30 In California, PacifiCorp is also subject to a separate “loading order” requirement that requires utilities to first meet growth in energy demand through energy efficiencyand demand response. Only after all cost-effective demandside measures have been taken should the utilities consider adding conventional generation technologies. 95 PacifiCorp’s 2011 IRP creates levelized cost curves for demand-side resources, as described above and in previous sections, and is a good example of this type of energy efficiency modeling effort. This type of modeling may be too costly to be feasible for some utilities, but it is important that consideration of various levels of DSM savings be given in integrated resource planning in order to give stakeholders confidence that all cost-effective DSM has been included in utility resource plans.

Supply options A full range of supply alternatives should be considered in utility IRPs, with reasonable assumptions about the costs, performance, and availability of each resource. There can be uncertainties regarding the availability and costs of raw materials and skilled labor, construction schedules, and future regulations. Because these cost uncertainties can affect technologies in different ways, it is prudent to model a range of possible costs and construction lead times for supply alternatives. And because planning periods examined in IRPs are typically a decade or more, it is also prudent to evaluate supply technologies that are not currently feasible from a cost perspective, but may become so later in the planning period.

Fuel prices Coal prices have been on the rise in recent years, and natural gas prices have historically been quite volatile. Fuel prices can shift as a result of demand growth, climate legislation, development of export infrastructure, and supply conditions. 96 It is thus extremely important to use reasonable, recent, and consistent projections of fuel prices in integrated resource planning.

Environmental costs and constraints Utility IRPs should include a projection of environmental compliance costs—including recognition, and evaluation where possible—of all reasonably expected future regulations. At this time, the EPA has announced several upcoming environmental regulations. A final version of the Mercury and Air Toxics Standards (the “MATS” Rule) has been released, and rules are pending for Coal Combustion Residuals (“CCR”), cooling water intake structures under the Clean Water Act (“316(b)”), updates to the National Ambient Air Quality Standards (“NAAQS”), and new Effluent Limitation Guidelines. Within the next three to five years, certain generating units may also become subject to new requirements under the Clean Air Act’s Regional Haze Program, sometimes known as the BART rule because it requires installation of “best available retrofit technology.” The Cross-State Air Pollution Rule, which would have required emissions reductions of SO 2 and NO

x in many states but was vacated by the US Court of Appeals for the DC Circuit in 2012, may return in a revised form at some point in the future. 97 Finally, greenhouse-gas emissions limits for electric generating units may come into effect in the next decade. 98 These rules, both individually and in combination, have the potential to dramatically change the electric power industry. Utilities, in their IRP filings, need to acknowledge these rules and prepare for them as best they can through evaluations of emissions allowance costs, emission controls, and changes to resource portfolios. Few utilities now do this in a comprehensive manner. Of those discussed here, APS does the best job in its IRP by providing a discussion of each of the rules and its potential impacts on APS operations. The process could be improved through analysis of different compliance strategy scenarios.

Existing resources Examination of existing resources in utility IRPs has become especially important as the mandated emission

95 See California Assembly Bills 1890 and 995. Similar loading order requirements exist in a few other states. See for example Connecticut Public Act No. 07-242, Section 51: An Act Concerning Electricity and Energy Efficiency.

96 Reviving Integrated Resource Planning. Page 6.

97 Colburn, K., et al. “Least-Risk Planning: The Homer City Decision Increases Uncertainty—but Rewards Forward Thinking.” Public Utilities Fortnightly, November 2012.

98 EPA has proposed but not yet finalized greenhouse gas emission limits for newly constructed power plants. After those rules are finalized, EPA is required under the Clean Air Act to develop standards for existing power plants.31 reductions associated with the MATS rule, discussed above, have led to utility decisions across the country to install pollution control retrofits, repower, or retire their coal units. PacifiCorp drew the ire of stakeholders and the Oregon PUC by not including this type of analysis for its coal-fired units in its 2011 IRP. All types of modifications to existing resources should be included in a utility’s analysis of the optimum resource portfolio.

Integrated analysis There are various reasonable ways to model plans, generally requiring the use of optimization or simulation models. Common models used throughout the industry include Strategist, EGEAS, System Optimizer, MIDAS, AURORA, PROMOD, and Market Analytics. These models are supplied to utilities by various third-party vendors. It is important that the integrated model does not inadvertently exclude combinations of options that deserve consideration. This might occur in one of two ways. The first is in the instances that future resource portfolios are user-defined, rather than selected by an industry model. This is one of the criticisms of the Arizona Public Service IRP: the use of production cost modeling without an optimization component may have resulted in a less than optimal addition of supply- and demand-side resources

over time. The second way in which this may occur is if users constrain optimization models so that a model may not, given the cost, select the quantity of a specific resource that it may want. For example, a utility may constrain a model in such a way that it is only allowed to add 100 MW of wind generation over the resource planning period; but depending on the nature of the utility’s electric system, the model may want to add additional wind resources. In this way, a combination of resources that deserves consideration may be excluded.

Time frame The study period for IRP analysis should be sufficiently long to incorporate much of the operating lives of any new resource options that may be added to a utility’s portfolio— typically at least 20 years—and should consider an “end effects” period to avoid a bias against adding generating units late in the planning period. Arizona rules require a 15-year planning period, Oregon a 20-year planning period, and Colorado a utility-specified planning period of between 20 and 40 years. Of the rules examined here, only Oregon explicitly states that an end effects period should be considered.

Uncertainty At a minimum, important and uncertain input assumptions should be tested with high and low cases to assess the sensitivity of results to changes in input values. These assumptions include, but are not limited to, load forecasts, fuel prices, emissions allowance prices, environmental regulatory regimes, costs and availability of demand-side management measures, and capital and operating costs for new generating units. 99 The types of inputs listed are common to most utilities across the United States, but there are additional input assumptions that are regional or local in nature. As discussed in the section on Oregon’s IRP rules, its PUC requires utilities to model cases that vary the amount of hydroelectric output in the region. Utilities in states like Arizona, New Mexico, or Florida may want to examine

99 Decisions in the face of uncertainty come with degrees ofrisk. A recent study by CERES entitled, “Practicing RiskAware Electricity Regulation: What Every State Regulator Needs to Know (How State Regulatory Policies Can Recognize and Address the Risk in Electric Utility Resource Selection) concludes that it is “essential that regulators understand the risks involved in resource selection, correct for biases inherent in utility regulation, and keep in mind the long-term impact that their decisions will have on consumers and society. To do this, regulators must look outside the boundaries established by regulatory tradition.” According to CERES, “risk arises when there is potential harm from an adverse event that can occur with some degree of probability.” Risks for electric system resources have both time-related (i.e., the possibility that circumstances will change over the life of the investment and materially affect both the cost of the investment and the degree to which it benefits consumers) and cost-related aspects (the possibility that an investment will not cost what one expects, or that cost recovery for the investment will differ from expectations). Practicing Risk-Aware Regulation (April 2012)at 20-21 http://www.ceres.org/resources/reports/practicingrisk-aware-electricity-regulation32 100 Reviving Integrated Resource Planning. Page 4. cases that vary the amount of solar output when doing long-term planning. Utilities located in arid regions, or those owning a significant number of generation assets that are dependent on the availability of a water source for power plant cooling, may want to analyze scenarios where water is scarce or is at too high a temperature to be useful for cooling. Individual utilities must determine those input assumptions that are subject to variability, and model sensitivity cases accordingly to properly account for risks and uncertainties that they face. Performing single-factor sensitivities may not, however, be very informative. Many cases may warrant more sophisticated techniques, such as probabilistic techniques or those that combine uncertainties. “Testing candidate resource solutions against scenarios that address the range of plausible future trajectories of external factors, and their interrelationships, can more effectively support planning in
an uncertain environment.” 100

Valuing and selecting plans There are often multiple stages of running scenarios and screening in developing an IRP, and there are various reasonable ways to approach this. Traditionally, the present value of revenue requirements is the primary metric that is analyzed, and minimized, in utility IRPs. This metric alone may not, however, sufficiently address uncertainties. It may be useful also to evaluate plans along other dimensions like environmental cost or impact, fuel diversity, impact on reliability, rate or bill increases, or minimization of risk. It is essential that the IRP process be executed in a manner that applies the selected metrics in a reasonably transparent and logical manner, without inappropriately screening out resources options or plans that deserve consideration at the next stage. Note also that it is highly unlikely that a single resource portfolio will be the best choice on every metric evaluated. A resource portfolio that performs well across several metrics, but perhaps is not the top performer on any single metric, may in fact be the best choice for utility planners.

Action plan Even though IRPs should have a longer study period, a good plan will include a specific discussion of the implications of the analysis for near-term decisions and actions, and will also include specific plans for getting those near-term items accomplished. Demand-side measures take time to implement, and supply-side resources require months or years of lead time to permit and construct. Utilities must thus provide a thorough discussion of the steps they plan to take to implement, acquire, or construct resources that will meet energy and peak demand needs in their service territories in the three- to five-year period after the plan is filed. The availability of these near-term resources has a direct effect on the resources needed throughout the remainder of the planning period; so it is prudent for the utility to detail the ways in which it will go about acquiring the resources described in its IRP.

Documentation A proper IRP will include discussion of the inputs and results, and appendices with full technical details. Only items that are truly sensitive business information should be treated as confidential, because such treatment can hinder important stakeholder input processes.33 

# V. Conclusion 

# U tility integrated resource planning has been in effect in various parts of the United States for more than 25 years. While some utilities are regulated by the original IRP rules developed more than a decade ago, many states have updated their IRP rules to reflect current conditions and concerns in regional and national electricity markets. In states where this has occurred, IRPs filed by utilities tend to be more comprehensive and to exhibit more of the “best practices” in utility resource planning that have been described in this
report. Nonetheless, there are still many ways in which utilities can improve both their resource planning processes and the plans that are generated as a result of these processes. Engaged stakeholders and state public utilities commissions can provide oversight to this process, helping to promote resource choices that lead to positive outcomes for society as a whole.34 Arizona Arizona Corporation Commission Decision No. 71722, in Docket No. RE-00000A-09-0249. June 3, 2010. 101

Arkansas Arkansas PSC. “Resource Planning Guidelines for Electric Utilities.” Approved in Docket 06-028-R. January 4, 2007. 102 Rules are currently under review and updates have been proposed.

Colorado Colorado PUC. 4 CCR 723-3, Part 3: Rules Regulating Electric Utilities. Decision No. C10-1111. Docket No. 10R-214E. November 22, 2010. 103

Delaware HB 6, the Delaware Electric Utility Retail Customer Supply Act of 2006. 104
Georgia Integrated Resource Planning Act of 1991 (O.C.G.A. § 46- 3A-1), Amended. 105
Georgia Public Service Commission. General Rules. Integrated Resource Planning 515-3-4. 106

Hawaii Public Utilities Commission, State of Hawaii, A Framework for Integrated Resource Planning, March 9, 1992. 107

Idaho Idaho Public Utilities Commission Order No. 22299, in
Case No. U-1500-165. 108

Indiana 170 Indiana Administrative Code 4-7-1: Guidelines for Integrated Resource Planning by an Electric Utility. New draft rules have been proposed in docket IURC RM 11-07. 109
Kentucky KY Administrative Regulation 807 KAR 5:058. Integrated Resource Planning by Electric Utilities. Relates to KRS Chapter 278. 110

Louisiana Louisiana Public Service Commission Corrected General Order. Docket No. R-30021. Decided at the Commission’s March 21, 2012 Business and Executive Session. 111 Minnesota MN Statute §216B.2422. 112

MN Rules Part 7843. 113

Missouri Rules of Dept. of Economic Development. Division 240 - PSC. Chapter 22—Electric Utility Resource Planning (4 CSR 240.22). 115

Montana Montana’s Integrated Least-Cost Resource Planning and Acquisition Act (§§ 69-3-1201-1206, Montana Code Annotated). 116
Administrative Rules of Montana 38.5.2001-2016, adopted by the Montana PSC, for traditional utilities. 117
Administrative Rules of Montana 38.5.8201-8227, adopted by the Montana PSC, for restructured utilities. 118

Nebraska Nebraska Revised Statute 66-1060. 119

Nevada
NRS 704.741. 120
New Hampshire Title XXXIV Public Utilities, Chapter 378: Rates and Charges, Section 38: Least Cost Energy Planning. 121

New Mexico Integrated Resource Plans for Electric Utilities, Title 17, Chapter 7, Part 3. 122

North Carolina North Carolina Utilities Commission Rule R8-60: Integrated Resource Planning and Filings. 123

North Dakota North Dakota PSC Order issued on January 27, 1987 in CaseNo. 10,799. Amended on March 11, 1992 in Case No. PU399-91-689. 124

Oklahoma Title 165: Oklahoma Corporation Commission. Chapter 25: Electric Utility Rules, Subchapter 37: Integrated Resource Planning. 125
Oregon Oregon PUC Order No. 07-002, Entered January 8, 2007. 126 

# Appendix: State IRP Statutes and Rules35 101 This Decision amends Arizona Administrative Code, Title 14, Chapter 2, Article 7: Resource Planning. It is available at: http://images.edocket.azcc.gov/docketpdf/0000112475.pdf

102 Arkansas guidelines available at: http://www.sosweb.state. ar.us/elections/elections_pdfs/register/june_07/126.03.07- 003.pdf

103 Colorado PUC Decision available at: https://www.dora.state. co.us/pls/efi/EFI.Show_Docket?p_session_id=&p_docket_ id=10R-214E

104 Delaware legislation available at: http://legis.delaware.gov/ LIS/lis143.nsf/vwLegislation/HB+6/$file/legis.html?open

105 Georgia annotated code available at: http://www.lexisnexis. com/hottopics/gacode/Default.asp

106 Georgia PSC rules available at: http://rules.sos.state. ga.us/cgi-bin/page.cgi?g=GEORGIA_PUBLIC_SERVICE_ COMMISSION%2FGENERAL_RULES%2FINTEGRATED_ RESOURCE_PLANNING%2Findex.html&d=1

107 Hawaii PUC Framework available at: http://www.heco. com/vcmcontent/Integrated%20Resource/IRP/PDF/IRP_ Framework_052292.pdf

108 Idaho PUC Order available at: http://www.puc.state.id.us/ search/orders/dtsearch.html

109 Indiana Administrative Code available at: http://www.in.gov/ legislative/iac/title170.html

110 Indiana docket RM#11-07 available at: http://www.in.gov/ iurc/2689.htm

111 Kentucky Administrative Regulation available at: http://www. lrc.ky.gov/kar/807/005/058.htm 112 Louisiana PUC Order available at: Rules from Arizona, Colorado and Oregon are described in detail in order to demonstrate ways in which states require comprehensive planning processes and resource plan outcomes from the utilities under their jurisdictions.

113 Minnesota Statute available at: https://www.revisor.mn.gov/ statutes/?id=216B.2422

114 Minnesota rules available at: https://www.revisor.mn.gov/ rules/?id=7843

115 Missouri rules available at: http://www.sos.mo.gov/adrules/ csr/current/4csr/4c240-22.pdf, Final Order of Rulemaking was issued on March 3, 2011, as part of the Missouri Public Service Commission Rulemaking Case No. EX-2010-0254. That amendment is available at: https://www.efis.psc. mo.gov/mpsc/commoncomponents/view_itemno_details. asp?caseno=EX-2010-0254&attach_id=2011015905

116 Montana Annotated Code available at: http://data.opi.mt.gov/ bills/mca_toc/69_3_12.htm

117 Montana Administrative Rules available at: http://www. mtrules.org/gateway/ChapterHome.asp?Chapter=38.5

118 Montana Administrative Rules available at: http://www. mtrules.org/gateway/ChapterHome.asp?Chapter=38.5

119 Nebraska Statute available at: http://nebraskalegislature.gov/ laws/statutes.php?statute=66-1060

120 Nevada Statute available at: http://www.leg.state.nv.us/nrs/ NRS-704.html#NRS704Sec741

121 New Hampshire Statute available at: http://www.gencourt. state.nh.us/rsa/html/NHTOC/NHTOC-XXXIV-378.htm South Carolina Code of Laws of South Carolina, Chapter 37, Section 58 37 40. Integrated resource plans. 127

Public Service Commission of South Carolina Order No. 91-885 in Docket No. 87-223-E. October 21, 1991. 128

South Dakota SL 1977, Ch. 390, § 23. Chapter 49-41B-3. 129
Administrative Rule Chapter 20:10:21, Energy Facility Plans. 130

Utah Report and Order on Standards and Guidelines. Docket No. 90-2035-01. Issued June 18, 1992. 131 Vermont 30VSA Sec 218c - Statute establishing least-cost integrated resource planning. 132
Public Service Board Order of 4/16/1990 initiating the IRP progress (Docket No. 5270). 133

Public Service Board Order of 7/16/2002 (Docket No. 6290). 134
Virginia Code of Virginia § 56-597 - § 56-599. 135
Washington Washington Administrative Code 480-100-238: Integrated Resource Planning. 136
Wyoming Wyoming Public Service Commission Rule 253 (submitted July 22, 2009), and associated Guidelines for Staff Review. 13736 122 New Mexico PRC Rule available at: http://www.pnm.com/ regulatory/pdf_electricity/irp_electricity.pdf

123 North Carolina PUC Rule available at: http://ncrules.state. nc.us/ncac/title%2004%20-%20commerce/chapter%20 11%20-%20utilities%20commission/04%20ncac%2011%20 r08-60.pdf

124 North Dakota PSC Order available at: http://www.raponline. org/docs/RAP_NDElectricResourceLongRangePlanningSurvey 2005_09_17.pdf

125 Oklahoma Rule available at: http://www.occeweb.com/rules/2 010Ch35ElectricpermanentMasterRuleseff7-11-10searchable. pdf

126 Oregon PUC Order available at: http://apps.puc.state.or.us/ orders/2007ords/07-002.pdf

127 South Carolina Code available at: www.scstatehouse.gov/ code/t58c037.docx

128 South Carolina PSC Order available at: http://dms.psc.sc.gov/ pdf/orders/DF4FC4A9-EB41-2CB4-D44614AD02D02B8D. pdf

129 South Dakota Statute available at: http://legis.state.sd.us/ statutes/DisplayStatute.aspx?Statute=49-41B-3&Type=Statute 130 South Dakota Rule available at: http://legis.state.sd.us/rules/ DisplayRule.aspx?Rule=20:10:21

131 Utah Order available at: http://www.airquality.utah. gov/Public-Interest/Current-Issues/Regionalhazesip/ RegionalHazeTSDdocs/Utah_PSC_Integrated_Planning_ Rules.pdf

132 Vermont Statute available at: http://www.leg.state.vt.us/ statutes/fullsection.cfm?Title=30&Chapter=005&Section=00
218c

133 Public Service Board Orders issued prior to 1996 are not available online.

134 Vermont PSB Order available at: http://www.state.vt.us/psb/ orders/2002/files/6290phaseIIextensionorder.pdf

135 Virginia Statute - content begins at: http://leg1.state.va.us/ cgi-bin/legp504.exe?000+cod+56-597

136 Washington Administrative Code available at: http://apps.leg. wa.gov/wac/default.aspx?cite=480-100-238

137 Wyoming PSC Rule available at: http://legisweb.state. wy.us/ARULES/2009/AR09-043.htm; Guidelines for Staff Review available at: http://psc.state.wy.us/htdocs/electric/ ElectricIRPGuidelines7-10.pdfThe Regulatory Assistance Project (RAP) is a global, non-profit team of experts focused on the long-term economic and environmental sustainability of the power and natural gas sectors. We provide technical and policy assistance on regulatory and market policies that promote economic efficiency, environmental protection, system reliability, and the fair allocation of system benefits among consumers. We work extensively in the US, China, the European Union, and India. Visit our website at www.raponline.org to learn more about our work.50 State Street, Suite 3 Montpelier, Vermont 05602

802-223-8199 www.raponline.org