Best Practices in Electric Utility 

Integrated Resource Planning

Examples of State Regulations 

and Recent Utility Plans

Authors

Rachel Wilson

Bruce Biewald

June 2013
Electronic 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

Best Practices in Electric Utility Integrated Resource Planning

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. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34
2

Best Practices in Electric Utility Integrated Resource Planning

An 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

Best Practices in Electric Utility Integrated Resource Planning

As 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

Best Practices in Electric Utility Integrated Resource Planning

An 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 Planning1

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 Initiatives: Integrated Resource Planning. 

July 2010. American Council for an 

Energy-Efficient Economy. Available 

at: http://aceee.org/policy-brief/utility-initiatives-integrated-resourceplanning

Load Forecast

Identify Goals

Action Plans

Existing Resources

Need for New Resources

Acquire Resources

Define Suitable Resource Mixes

Supply Demand T & D Rates

Monitor

Uncertainty 

Analysis

Public Review/

PUC Approval

Social 

Environmental 

Factors
5

Best Practices in Electric Utility Integrated Resource Planning

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 setting include adding generating capacity (thermal, renewable, 

customer-owned, or combined heat and power), adding 

transmission and distribution lines, and implementing energy 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

Nevada Nebraska

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 (CO2) 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

Best Practices in Electric Utility Integrated Resource Planning

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 Rules
7

Best Practices in Electric Utility Integrated Resource Planning

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 customers 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 and 

transmission 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 transmission 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 in 

operating 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 resources 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

Best Practices in Electric Utility Integrated Resource Planning

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 

Requirements

As 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

Best Practices in Electric Utility Integrated Resource Planning

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

Best Practices in Electric Utility Integrated Resource Planning

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

Best Practices in Electric Utility Integrated Resource Planning

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

Best Practices in Electric Utility Integrated Resource Planning

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 from 

these 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

Best Practices in Electric Utility Integrated Resource Planning

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

33 4 Code of Colorado Regulations 723-3. Part 3: Rules Regulating 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 those 
14

Best Practices in Electric Utility Integrated Resource Planning

resources, 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 CO2 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 review 
15

Best Practices in Electric Utility Integrated Resource Planning

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

Best Practices in Electric Utility Integrated Resource Planning

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

Arizona 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 CO2 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, CO2 prices, production and 

investment tax credits for renewable resources, energy 

efficiency costs, and monetization of SO2, NOx, PM, and 

water. APS also created low-cost and high-cost scenarios, 
17

Best Practices in Electric Utility Integrated Resource Planning

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 IRP51

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 a 
18

Best Practices in Electric Utility Integrated Resource Planning

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 Portfolio52

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 

CO2 adder consistent with the assumption that federal 

regulation of CO2 will occur within the 15-year planning 

period. In sensitivity scenarios, APS analyzes alternative 

prices for CO2 emissions, and also includes adders for 

SO2, NOx, 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.”55
19

Best Practices in Electric Utility Integrated Resource Planning

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 shortly 

after 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 CO2 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 adding 
20

Best Practices in Electric Utility Integrated Resource Planning

Figure 5

Least-Cost Baseline Case and Alternative Plans During the Resource Acquisition Period (RAP) 

From Public Service Company of Colorado’s 2011 IRP58

Figure 6

Sensitivity Results for Co2, Tax Incentives, and Gas Prices From 

Public Service Company of Colorado’s 2011 IRP59

RAP 

Resource 

Thermal 

Resources

Wind

Solar

Battery

Solar 

Thermal

Starting 

Assumptions

CO2 3-Source Low 

Esc

CO2 3-Source

CO2 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 A

Sensitivities

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

Best Practices in Electric Utility Integrated Resource Planning

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 reserve 

margin 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

Best Practices in Electric Utility Integrated Resource Planning

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 on 

a 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 IRP68
23

Best Practices in Electric Utility Integrated Resource Planning

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 Portfolio70

Figure 9

Energy Mix Under the PacifiCorp 

Preferred Portfolio71

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

Best Practices in Electric Utility Integrated Resource Planning

Altogether, PacifiCorp defined 67 input scenarios 

for portfolio development. These looked at alternative 

transmission configurations, CO2 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 Process73

criteria as risk-adjusted portfolio cost, 10-year customer 

rate impact, CO2 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 the 

country 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 CO2 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

CO2 Cost 

Assumptions

Gas 

Prices

IPM model runs 

(National)

CO2 cost responses: 

Gas basis differentials 

and SO2 prices

MIDAS model runs 

(Western)

CO2 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

Best Practices in Electric Utility Integrated Resource Planning

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 estimate 

of 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 two 

categories: 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

Best Practices in Electric Utility Integrated Resource Planning

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 may 
27

Best Practices in Electric Utility Integrated Resource Planning

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

Best Practices in Electric Utility Integrated Resource Planning

83 State and Local Energy Efficiency Action Network. Using 

Integrated 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 factors83 and 

should be fully documented. Resource needs can rise or fall 

dramatically 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 efficiency 

measures 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

Best Practices in Electric Utility Integrated Resource Planning

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. In 

Arizona, 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 most 

recent 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

Best Practices in Electric Utility Integrated Resource Planning

In California, PacifiCorp is also subject to a separate 

“loading order” requirement that requires utilities to first 

meet growth in energy demand through energy efficiency 

and 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 SO2 and NOx 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

Best Practices in Electric Utility Integrated Resource Planning

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 of 

risk. 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-regulation
32

Best Practices in Electric Utility Integrated Resource Planning

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

Best Practices in Electric Utility Integrated Resource Planning

V. Conclusion

Utility 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

Best Practices in Electric Utility Integrated Resource Planning

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 Case 

No. 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 Rules
35

Best Practices in Electric Utility Integrated Resource Planning

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.137
36

Best Practices in Electric Utility Integrated Resource Planning

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.pdf
The 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