ITEM NO. 1

PUBLIC UTILITY COMMISSION OF OREGON

STAFF REPORT

PUBLIC MEETING DATE: March 17, 2014

REGULAR X CONSENT EFFECTIVE DATE

Upon 

Commission Approval

DATE: March 4, 2014

TO: Public Utility Commission

FROM: Juliet Johnson

THROUGH: Jason Eisdorfer, Maury Galbraith, and Aster Adams

SUBJECT: PACIFICORP: (Docket No. LC 57) Acknowledgement of 2013 Integrated 

Resource Plan.

STAFF RECOMMENDATION:

Staff recommends the Commission acknowledge PacifiCorp’s 2013 Integrated 

Resource Plan (IRP) with revised action items as reflected in Attachments B and C. In

our final comments and the discussion below Staff presents the reasons underlying 

these recommended action item revisions. 

DISCUSSION: 

On August 22, 2013, Oregon Public Utility Commission Staff (Staff), Citizens Utility 

Board (CUB), Industrial Customers of the Northwest Utilities (ICNU), Northwest Energy 

Coalition (NWEC), Natural Resources Defense Council (NRDC), Oregon Department of 

Energy (ODOE), Renewable Northwest Project (RNP), Sierra Club filed Initial 

Comments regarding PacifiCorp’s 2013 IRP (Docket No. LC 57). On November 26, 

2013, PacifiCorp (or Company) filed reply comments. On January 10, 2014, final 

comments were filed by Staff, CUB, ICNU, NWEC, ODOE, RNP and Sierra Club. On 

January 17, 2014, CUB and Sierra Club filed supplemental comments. On February 4, 

2014 PacifiCorp filed final written comments. 

Staff discusses below the comments filed by the parties and the Company, organized 

by subject. Attachment A contains the Company’s originally filed action items. 

Attachment B contains Staff’s recommended redlined changes to the Company’s action 

items and Attachment C contains a clean copy of Staff’s proposed changes to the 

Company’s action items reflecting Staff’s proposed changes. Many of PacifiCorp’s 
Staff Report LC 57

March 4, 2014

Page 2

action items are not planning items but rather are activities the Company would do in 

the regular course of business. For those items, Staff suggests that acknowledgement 

is not required and Staff proposes to remove them from the list of action items. 

1. SEPARATE COAL ANALYSIS DOCKET

In PacifiCorp’s reply and final comments, the Company indicates that it supports a new 

planning and review process in Oregon for coal unit investments to allow the parties to 

develop parameters for coal investment analyses and allow the Company to seek 

acknowledgement of specific emissions control investments or alternatives. On 

January 6, 2014, all parties met to discuss the option of such a separate outboard coal 

analysis docket.

Staff Recommendation

In our final comments, Staff indicated support for a separate coal analysis docket for 

cases where timing does not line up with the standard IRP schedule. Staff emphasized 

that a new docket should not diminish the rigor of the current IRP process or result in

pre-approval of investment decisions. One of the primary values of integrated resource 

planning is that individual resource decisions are viewed from a whole portfolio 

perspective. Accordingly, it is important that coal plant investments also be viewed 

within the larger context of PacifiCorp’s portfolio of resources. Because of this, Staff 

contends it is ideal, if possible, for all coal plant investments to be considered within the 

full IRP process, rather than through separate proceedings. 

Because of Staff’s timing concerns regarding required pollution control investments at 

Cholla Unit 4, Staff continues to support an opportunity to evaluate pollution control 

alternatives for Cholla Unit 4, prior to the 2015 IRP. However, based on further 

discussions with the Company and based on the timing of pollution control requirements 

in the recently released Wyoming Federal Implementation Plan (FIP),

1 Staff sees little 

need for a separate coal analysis docket going forward, beyond Cholla. Decision points 

for future investments should align well with IRP cycles. As originally envisioned, the 

separate coal analysis docket would have included significant effort to establish the 

parameters and protocols for how investments would be considered in such a docket 

 

1 Potential pollution control investments for Wyodak (Selective Catalytic Reduction (SCR) by 

March 2019) and Dave Johnston 3 (SCR by March 2019 or firm commitment to retire plant in 

2027) can be addressed in the 2015 IRP. Regulatory requirements for Bridger 1 and 2 (SCRs 

required by the end of 2022 and 2021, respectively) should also fit within the timing of the 

regular IRP cycle. Therefore, based on what is now known, there may be limited necessity for 

a separate designated coal analysis docket, beyond Cholla Unit 4. 
Staff Report LC 57

March 4, 2014

Page 3

and to define the types of analysis that would be brought forth. Staff does not believe it 

is justified to go through such rigorous process to establish the framework for a 

complete separate coal analysis docket that would only be used for Cholla Unit 4. 

Staff does, however, believe a separate process is necessary to come to agreement on 

the types of coal plant analysis that should be provided by the Company in future IRPs. 

Staff’s recommendations to that effect are summarized in the next section.

Instead, Staff recommends the Company bring the Cholla analysis back to the 

Commission through a special IRP update and parties and the Commission can review

the investment at that time. See the section on Cholla Unit 4 below for a proposed 

update to Action Item 8d to this effect. 

Other Parties’ Positions

ICNU is opposed to the Commission acknowledging unit-specific coal plant investments 

decisions in a separate coal analysis docket because the Commission’s IRP policies do 

not contemplate and have never been used to review individual, specific resource 

decisions outside of the context of a full IRP or IPR update. ICNU suggests that the 

Commission’s final order can direct PacifiCorp to continue to provide parties with 

additional information regarding its coal plant investments, to conduct specific analysis, 

and even to seek comments from stakeholders; however, ICNU asserts the 

Commission should not acknowledge or pre-approve any specific investments in a 

follow-on proceeding. 

RNP says that coal plants with required upgrades over the next five years need to be 

considered collectively and immediately. RNP suggests it would be ideal to extend the 

IRP to obtain that analysis, but if the IRP is not extended, RNP supports an additional 

coal investigation docket.

NWEC is skeptical about whether a separate docket will result in adequate analysis, but 

says it may be worth exploring. 

Sierra Club conditionally agrees that an ongoing coal investment docket would be of 

high value if it had the following attributes:

 A schedule that would allow for discovery and additional model runs requested 

by interveners;

 Opportunity to provide formal comments on the modeling assumptions, results, 

implications, and recommended pathways; 

 Commission would provide no expectation of a planning pre-approval or 

determination of planning prudence;
Staff Report LC 57

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Page 4

 Docket opened within a year of U.S. Environmental Protection Agencies (EPA’s)

final rulemaking (i.e., finalized FIP or State Implementation Plan (SIP)), but in no 

case later than eight months prior to the Company giving notice to proceed to 

contractors; 

 Company agree to multi-unit analyses as applicable;

 All of the Company’s units must be subject to economic analysis regardless of a 

given plant’s ownership structure; 

 The same information requirements and deadlines should apply regardless of 

whether the Company engages in lawsuits;

 In addition to evaluating transmission implications of the Company’s decisions, 

the analysis should capture other reasonably attributable costs and avoidable 

costs of retirement. 

Sierra Club said it would be important to establish minimum data requirements for the 

coal investment dockets. In Sierra Club’s final comments, they provide a list of specific 

data that should be provided. With all the conditions described above, Sierra Club 

supports establishment of the coal investment docket.

In CUB’s final comments, it does not explicitly comment on the Company’s proposed 

separate coal analysis docket, but rather proposed a general analytical framework for 

coal plant investments going forward. CUB’s specific suggestions are presented later in 

this document. 

PacifiCorp Response

In response to ICNU, PacifiCorp emphasizes that it would not be seeking pre-approval 

of specific coal unit investments in a separate coal analysis docket. Rather the 

Company would use the process to seek acknowledgment of specific investment 

decisions that would be supported by analysis using IRP modeling tools. PacifiCorp 

would expect the process to proceed in a manner similar to the current IRP 

acknowledgement process, with parties filing comments and the Company filing reply 

comments that the Commission would consider before issuing an acknowledgement 

order. 

PacifiCorp indicates that if the Commission accepts the recommendation for a separate 

coal investment docket PacifiCorp would propose to bring the Cholla investment 

decision to the Commission in that docket sometime in 2014.

Staff Recommendation

Staff recommends that a new separate coal analysis docket where the Company would 

seek acknowledgement of individual coal plant investments not be pursued at this time. 

However, Staff recommends that the Company bring its analysis of Cholla Unit 4 to the 
Staff Report LC 57

March 4, 2014

Page 5

Commission in a special IRP Update within six months of the final order in this docket 

and with enough time to allow for all potential reasonable pollution control alternatives 

for Cholla to be pursued. In the following section, Staff lays out our recommendation 

for a separate process to come to agreement on analyses for coal plants that should be 

provided in future IRPs.

2. COAL ANALYSIS 

Staff Position

A significant portion of the Company’s planned capital expenditures in recent and 

upcoming years centers around pollution control investments at the Company’s coal 

plants. Staff appreciates the additional coal plant investment analyses the Company 

provided in this IRP, beyond what was provided in past IRPs. However, Staff feels 

strongly that more comprehensive analysis is needed prior to committing Oregon 

ratepayers to these large pollution control investments. In our final comments in this 

docket and at a technical workshop held on January 6, 2014, Staff described in detail 

the types of analyses Staff needs to see going forward, in order to make 

recommendations to the Commission on coal plant investments.2 

Other Parties’ Response

NWEC believes the Company continues to underestimate the cost and risk of continued 

reliance on coal generation which they fear will saddle ratepayers with high 

environmental upgrade costs, stranded costs, or both.3 NWEC indicates that the 

Company failed to analyze several coal units that should have been evaluated in this 

IRP and that the Company is not adequately analyzing coal plant upgrades prior to 

committing to those investments. For this reason, NWEC suggests the 2013 IRP fails to 

comply with IRP Guidelines 4g4and 8a5.

NWEC suggests that analyses requested by Staff at the technical workshop on January 

6, 2014, combined with sufficiently stringent environmental compliance and carbon price

 

2

LC 57 Staff final comments page 2 and Appendix B

3 NWEC final comments LC 57 page 5.

4 Guideline 4g requires the IRP to include an identification of key assumptions about the future 

(e.g., fuel prices and environmental compliance costs) and alternative scenarios considered.

5 Guideline 8.a. states, in part, that the utility should construct a base-case scenario to reflect 

what it considers to be the most likely regulatory compliance future for CO2 and several 

compliance scenarios ranging from the present CO2 regulatory level to the upper reaches of 

credible proposals by governing entities.
Staff Report LC 57

March 4, 2014

Page 6

scenarios would likely capture the range of options necessary for an adequate 

analysis.6 

CUB expressed concerns that the breadth of possibilities evaluated was too narrow and 

that more possibilities should have been modeled. CUB refers to page 56 of 

PacifiCorp’s Reply Comments where the Company states that because EPA’s regional 

haze requirements have not been formalized, they have “no bearing on the 

environmental investments identified in the 2013 IRP Action Plan.” CUB points out that 

notwithstanding that fact, the EPA has proposed controls outside the scope of the 

Company’s modeling, and this suggests that there existed a broader range of 

possibilities that should have originally been considered by the Company. 

CUB also expressed concern about the mismatch of useful lives of pollution control 

upgrades and the plants on which those upgrades would be installed. The Company is 

telling the EPA it must use the shorter useful life if the depreciable life of the plant is less 

than 20-years. CUB points out that the Company seems to contradict itself because on 

one hand PacifiCorp acknowledges EPA cannot use in its compliance calculations a 

shorter life than the pollution control measure unless there is a firm shutdown 

commitment, while on the other hand PacifiCorp argues that the EPA must consider a 

shorter shutdown life without a firm commitment to closure. In the final comments, the 

Company does not address this apparent inconsistency.

The third issue CUB raises is regarding the cost-effectiveness limit in dollars of pollution 

control equipment required per ton of pollution removed ($/ton) that EPA uses to 

evaluate the cost-effectiveness of new pollution control requirements. CUB and the 

Company agree that EPA has not set an exact $/ton threshold. CUB is concerned that 

the Company only considered scenarios that are either:

a) on the high end of the possible range of cost effectiveness tests for pollution 

controls, which results in choosing a high estimate of the pollution control 

costs associated with early plant closures, or

b) on the low end of the possible range of closure dates, which is reducing the 

benefit of running the plant.

Both a) and b) above have the result of reducing the cost-effectiveness of the plausible 

scenario. CUB instead suggests the Company should investigate whether there is a 

plausible scenario that is also least cost. It would do this by looking at the low end of 

 

6

Analysis requested by Staff at January 6, 2014 workshop is summarized in Staff’s final comments in LC 

57, Appendix B.
Staff Report LC 57

March 4, 2014

Page 7

the possible range of cost-effectiveness tests and the high end of the remaining life of 

the plant. CUB suggests this plausible low cost scenario could be discussed with EPA. 

In its final comments, CUB recommends an analytic framework going forward that 

includes the following three steps:

1) Analyze the cost of the potential pollution controls under a range of pollution 

control scenarios 

a. Include what is known

b. What is likely

c. Upper range of what might happen

2) Compare alternatives from item 1 above to alternative investments such as

a. Repowering with gas

b. Building a combined cycle combustion turbine (CCCT)

c. Relying on front office transactions

3) Investigate whether there is a plausible scenario for an early closure that is lower 

cost than options above

a. Begin by looking at the low end of the range of what EPA will consider 

cost effective

b. Look at the high end of the range of years before closure that EPA might 

accept

c. If a plausible cost-effective scenario is identified, further examine 

additional plausible scenarios to determine upper and lower ranges for a 

cost-effective early closure

4) Where depreciable life is less than 20 years, analyze whether committing to 

close at the end of the depreciable life would reduce pollution control costs 

because less or different pollution control investments need to be made

In CUB’s supplemental comments, issued after EPA released the finalized FIP for 

Wyoming on January 10, 2014 CUB requests the Commission require PacifiCorp to 

update its original and supplemental LC 57 filings to include analysis of both Wyodak 

and Dave Johnston because they both require potential action by 2019. 

RNP indicates that there remain considerable limitations in the coal analysis provided. 

RNP says it strongly supports Staff’s opening comments which list the ways in which 

PacifiCorp’s IRP coal upgrade analysis can be expanded. RNP agrees that the 

reasonableness of coal plant investments should not be determined through an IRP 

update. Further, RNP concurs with Staff that coal plants with required upgrades over 

the next five years need to be considered collectively and immediately. Finally, RNP 

points out that future IRP analysis should include trigger analysis demonstrating at what 

gas price and CO2 cost, investments at legacy coal units have no system costs or 

benefits and that if necessary, tools other than System Optimizer should be used. 
Staff Report LC 57

March 4, 2014

Page 8

Company Response

PacifiCorp states that its analysis of pollution control investments is comprehensive, 

covering viable compliance alternatives across a range of natural gas and CO2 price 

assumptions.

In PacifiCorp’s final comments, it proposes that additional work is required before a 

specific modeling framework can be established that is acceptable to both the Company 

and the parties. PacifiCorp recognizes that parties want PacifiCorp to consider flexible 

compliance alternatives and transmission implications for specific investment decisions 

and that parties want improved transparency on model inputs and outputs and want to 

have an opportunity to define specific scenarios. 

In PacifiCorp’s final comments, on page 6, the Company reasserts its opinion that 

completing preliminary analysis of prospective environmental investments must be 

based on reasonably likely compliance alternatives that are consistent with current 

rules. The Company says that completing premature analysis does not provide 

meaningful information to support a specific resource action for which the Company 

would seek acknowledgement. PacifiCorp indicates that outcomes in EPA’s final action 

that are new and binding will be thoroughly reviewed and analyzed in future regulatory 

filings.

Staff Recommendation

Staff’s four main concerns with the Company’s coal analysis are, a) a deficiency in the 

number of dates considered for adding pollution control equipment, shutting down or 

converting to gas (Staff refers to this as inter-temporal analysis), b) the Company did

not look at potential tradeoffs between units or between plants (Staff calls this fleet 

analysis), c) the Company did not evaluate proposing alternative types of treatment and 

levels of pollutant removal in exchange for changing plant retirement dates or cross-unit 

tradeoffs (Staff refers to this as technology tradeoffs), and d) the Company did not

incorporate the impact of alternatives on the need for or sizing of new transmission 

lines. See Staff’s final comments, Appendix B for details.

The Company has expressed a willingness to work with Staff and stakeholders to 

develop the appropriate types of coal investment analyses for future proceedings. 

However, in meetings designed to discuss analyses that should be provided going 

forward, the Company expressed a reluctance to perform what Staff believes is a 

comprehensive set of scenarios. For that reason, Staff is proposing an action item that 

specifies a minimum set of analyses the Company should perform in the next IRP. See 

Section 2.1 below for details. Staff has thought through this in depth and believes this is 

a reasonable set of alternatives to evaluate, given the magnitude of investments being 

anticipated. 
Staff Report LC 57

March 4, 2014

Page 9

In the finalized Wyoming FIP released by EPA on January 10, 2014, EPA required that 

PacifiCorp’s Wyodak coal plant install SCR equipment by March 2019. Staff looked 

closely at how Wyodak is situated in relation to Class 1 areas7and other plants in 

PacifiCorp’s fleet and developed a set of alternatives in terms of cross plant, early 

retirement and technology tradeoffs that should be modeled. These are described in 

the tables below. Staff believes this is a good start and asks the Commission to 

acknowledge that this is the minimum analysis PacifiCorp should provide for Wyodak in 

the next IRP. 

Staff also recommends that in the final commission order in this docket the Commission 

direct Staff to initiate a series of workshops with the Company and interveners, and at 

least one workshop with the Commissioners to discuss the specific analyses that will be 

provided in the 2015 IRP and modify the specific runs listed below. Staff recommends 

that the final results of the workshops be summarized by Staff in a public meeting memo 

along with Staff recommendations and brought before the Commission at a public 

meeting. The Company and parties could respond to Staff’s memo in advance and/or 

at the public meeting and the Commission would make the final determination of which 

fleet analysis PacifiCorp will conduct in its next IRP. PacifiCorp is free to elaborate and 

expand on this analysis, but it would serve as a baseline fleet analysis.

Staff recommends the Commission acknowledge the following new action item for 

Wyodak.

New Action Item 8f. - Wyodak

 For the 2015 IRP the following inter-temporal and fleet trade-off analysis related 

to the SCR requirement on Wyodak by 2019 will be used as a frame of 

reference:

Inter-temporal Scenarios

EPA 

requirement

Time 1 Time 2 Time 3

Wyodak

Plant 

Action

SCR Retrofit SNCR Retrofit / 

early retirement

Gas 

Conversion Retirement

Timeline 2019 2019 / 2030 2022 2027

 

7

The EPA has identified Class 1 areas as nationally significant scenic areas that are targeted for 

improved visibility through the reduction of regional haze.
Staff Report LC 57

March 4, 2014

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Fleet Trade-Off Scenarios 

EPA 

requirement

Fleet 1 Fleet 2 Fleet 3 Fleet 4

Wyodak SCR Retrofit 

in 2019 No Action No Action No Action No Action

Dave Johnston Units 1 & 

2

No Action Retirement 

in 2027 No Action

Gas 

Conversion in 

2022

No Action

Dave Johnston Unit 4 No Action No Action Retirement 

in 2027 No Action

Gas 

Conversion in 

2022

o The timing and options will be finalized with stakeholders at the workshops 

for the 2015 IRP.8

o This analysis will include considerations for the necessity of Gateway 

West with reduced capacity in eastern Wyoming

o Workshops will be held, including at least one with the Commissioners, to 

refine the list of specific fleet analyses to be performed in the IRP. Staff 

will bring final recommendations to the Commission at a Public Meeting 

and the Company and parties will have an opportunity to respond.

2.1 Carbon Risk 

Parties’ Positions

Many parties voiced concerns that PacifiCorp’s analysis does not adequately account 

for the risks associated with carbon. RNP points out that PacifCorp’s base case CO2 

cost assumptions do not contemplate the federal CO2 regulation articulated in the 

Obama Administration’s June 2013 Presidential Memorandum. RNP suggests that 

because of this, the Commission should review the reasonableness of PacifCorp’s 

proposed action plan under the high CO2 cost assumptions rather than the base case 

assumptions used to justify the proposed resource strategy. RNP suggests that Section

111(d) rulemaking process9resulting from the President’s Memorandum merits a 

change in PacifiCorp’s forecast of CO2 regulation. 

 

8

Staff recognizes that running numerous futures scenarios in System Optimizer (SO) for each of the 

Scenarios shown in the tables above is untenable and looks forward to working with PacifiCorp and 

parties to limit the number of SO model runs.

9 Clean Air Act section 111(d) requires EPA to establish regulations under which States will 

regulate existing sources of carbon emissions. 
Staff Report LC 57

March 4, 2014

Page 11

RNP believes that the range of carbon forecasts used in the IRP is reasonable, however 

the specific base case forecast used to justify action items 8b (compliance actions at 

Hunter) and 8c (compliance actions at Bridger) is no longer a reasonable assumption 

because of the Presidential declaration and therefore, high CO2 scenarios should be 

used instead. 

ODOE recommends the Commission find that this IRP does not comply with IRP 

Guideline 8a or Order No. 08-339 which says, in part, that the utility should construct a 

base-case scenario to reflect what it considers to be the most likely regulatory 

compliance future for CO2 and several compliance scenarios ranging from the present 

CO2 regulatory level to the upper reaches of credible proposals by governing entities. 

ODOE suggests the Commission should instruct PacifiCorp in its next IRP to analyze 

the Oregon 2050 CO2 reduction goal applied to the U.S. or the Cancun agreement 

signed by the U.S., whichever is more restrictive. ODOE also suggests the Commission 

should carefully scrutinize all action items in the action plan that might have been 

subject to additional risk had a higher range of possible carbon policies been used in 

the risk analysis. Lastly, ODOE recommends that the Commission should instruct 

PacifCorp that “credible proposals by governing entities” includes adopted plans and 

actions by other democratically-elected sovereign states.10

NRDC also notes that PacifiCorp does not appear to have revised its expectations of 

federal CO2 regulation despite the President’s direction and the EPA Director’s stated 

resolve to comply. Because of this, NRDC indicates that PacifiCorp’s analysis and 

conclusions are flawed and investment decisions being proposed may result in 

significant future stranded costs. 

Sierra Club expressed concern that the Company’s base carbon price forecast used in 

this IRP was insufficient to capture the risk associated with impending federal 

regulations. 

Company Response

In PacifiCorp’s reply comments, submitted on November 8, 2013, the Company says 

that despite issuance of the 2013 Presidential Memorandum, there is tremendous 

uncertainty about the regulatory mechanisms that might be used in EPA’s pending rulemaking process and the cost of future regulations on CO2 emissions. PacifiCorp

indicates that absent information on how EPA intends to proceed and without 

information on how individual states will propose to implement regulations through a 

state implementation plan (SIP), there is currently no means to develop a specific CO2 

price assumption that accurately reflect potential CO2 regulation. For this reason, 

PacifCorp states it believes the CO2 assumptions used in the 2013 IRP remain 

 

10 ODOE LC 57 final comments, page 4.
Staff Report LC 57

March 4, 2014

Page 12

reasonable. PacifiCorp also states it will re-evaluate CO2 price assumptions in the 

development of the 2015 IRP.

Staff Recommendation

Staff recognizes that PacifiCorp’s IRP was submitted prior to the 2013 Presidential 

Memorandum regarding carbon pollution. In Staff’s initial comments, we said that we 

were not convinced that an across-the-board carbon price was an appropriate way to 

estimate cost and risk for potential carbon pollution standards as described in the 

President’s action plan. Although Staff finds that the carbon prices used in PacifiCorp’s 

IRP begin later and are lower than some estimates, Staff does not find that the 

Company’s analysis or results are fundamentally flawed due to the range of carbon 

prices used or how the prices were applied in the Company’s analysis. 

In light of potential Section 111(d) regulations, in future analyses and IRPs, the 

Company needs to consider scenarios where an across the board carbon tax may not 

be the best simulation. Staff has identified three potential forms 111(d) carbon 

regulation could take:

1) State by state compliance requirements where PacfiCorp must demonstrate 

reasonable progress – the use of an across-the-board carbon price doesn’t 

simulate this scenario well

2) State by state regulation with regional cooperation – An across the board carbon 

price may partially simulate this future 

3) Regional or national targets with allowance for Regional Greenhouse Gas 

Initiative (REGGI), etc - An across the board carbon price simulates this 

potential future reasonably well

Once EPA’s proposed requirements are released in June 2014, the Company should 

work with Staff and stakeholders to review how the Company plans to perform analysis 

and make plans given the proposed 111(d) regulations. To that effect, Staff 

recommends the following additional action item:

New Action Item 8g – Carbon Analysis

Prior to the end of 2014, the Company will work with Staff and stakeholders to 

explore options for how the Company plans to model and perform analysis in the 

2015 IRP related to what is known about the requirements of Section 111(d).
Staff Report LC 57

March 4, 2014

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2.2 Screening Tool

Staff continues to have concerns about the lack of transparency and accessibility of the 

Company’s modeling program System Optimizer. Staff appreciates the Company’s

commitment in its reply comments that it will work to improve the transparency of the 

data that is going into and coming out of System Optimizer. Staff agrees that this will be 

a big improvement. In Staff’s initial comments, comments provided at the workshop 

held on October 28, 2013, and in Staff’s final comments, we emphasized that we would

like to receive updated copies of the screening tool spreadsheet model the Company 

developed for the 2011 IRP Update in LC 52. Staff is proposing to add an action item to 

that effect. 

NWEC suggests the Company provide Staff and interveners with tools to improve the 

basic understanding of the coal resource investments. These tools include:

1) an updated screening tool

2) documentation of timelines and key decision points for expected pollution 

control options.

From here, NWEC believes Staff and interveners could attempt to reach agreement on 

a sufficient scope for an updated coal study.

NWEC voiced frustration about the ability of interveners to evaluate inputs and outputs 

from the System Optimizer model, which NWEC refers to as a “giant black box”. NWEC 

states that this leads to seemingly never-ending assertions that the Company failed to 

perform the correct analysis. In contrast, the screening tool provided in conjunction with 

the 2011 IRP coal analysis process allowed interveners to more clearly understand the 

relationship between inputs and outputs in the coal analysis and to look for 

combinations that might provide insight into least cost/least risk strategies for coal unit 

decisions. 

Sierra Club stated that while it recognizes the screening tool is not a perfect 

representation of the Company’s dispatch, and does not capture least-cost alternatives 

or tradeoffs between existing coal units, it is a transparent mechanism of reviewing 

particular investment strategies and identifying concerns. Sierra Club said that it 

supports the use of the screening model or other similar mechanisms to allow 

PacifiCorp’s regulators and other stakeholders to review PacifiCorp decisions.

Company Response

PacifiCorp asserts that the screening model was developed as part of the 2011 IRP 

process as a way to prioritize more detailed analysis using System Optimizer and was 

not used to evaluate economic benefits for any given pollution control investment 

decision. PacifiCorp points out multiple “limitations” of the screening tool including a) 
Staff Report LC 57

March 4, 2014

Page 14

compliance alternatives are limited to early retirement; b) replacement resources are 

limited to natural gas combined cycle combustion turbines; c) replacement CCCTs are 

scaled to precisely match the size of the coal unit being retired; d) replacement resource 

comes on-line concurrent with coal unit retirement; e) resource portfolio implications of 

early retirement are not captured; f) it cannot capture system constraints including 

transmission and system balancing sales and purchases; and g) it relies on a simplified 

representation of unit dispatch.11

In short, PacifiCorp argues that the screening tool cannot capture the system 

implications or alternatives. 

Staff Recommendation

Staff understands the limitations of the screening tool described by the Company. Staff 

does not view the screening tool as perfect, by any means, nor as a replacement for the 

System Optimizer. Staff, however, contends it is still a very useful tool that Staff and 

interveners can use in conjunction with the System Optimizer and PaR analysis. Staff is

not suggesting the screening tool replace the System Optimizer, but rather that it be 

used only as it was intended, as a screening tool. The screening tool would be useful to 

Staff and other parties in that it will facilitate their understanding of the Company’s case 

and will facilitate and support their analysis.

Staff is concerned that there is a serious lack of transparency in the Company’s current 

analysis. Model inputs, outputs and overall System Optimizer model parameters are 

not reasonably accessible to Staff and interveners and results are not reproducible. 

Providing an updated version of the screening tool with each IRP should not take a 

substantial effort by the Company and would be an important step toward providing 

some transparency of PacifiCorp’s analysis. Staff is confident that interveners would 

respect the limitations of the screening tool while using it as it should be used – as a 

screening tool. 

Staff recommends addition of the following action item:

New Action Item 8h. – Screening Tool

As part of the 2015, 2017 and 2019 IRP, the Company shall provide an updated 

version of the screening tool spreadsheet model that was provided to Staff and 

parties as part of the LC 52 2011 IRP Update.

 

11 See LC 57 PacifiCorp Reply Comments at 16.
Staff Report LC 57

March 4, 2014

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2.3 Timing of resources and more information

The Sierra Club argues that projects that are in active construction should be 

considered in a rate recovery proceeding not in a planning resource proceeding. In 

ICNU’s comments on Sigurd to Red Butte, it points out that the goal of an IRP is to seek 

acknowledgement of the Company’s plans to meet expected loads based on its 

expected costs, risks and uncertainties and not what the Company is already building. 

On that basis ICNU recommends the Commission not acknowledge Sigurd to Red 

Butte.

Staff Recommendation

Staff maintains that timing is important and robust analysis needs to be provided to the 

Commission, Staff, and parties with sufficient time for parties to see and evaluate the 

results prior to key investment decisions being made that might limit viable options 

going forward. Staff prefers that the Company does not bring items before the 

Commission in an IRP that are currently under construction. However, under limited 

circumstances when the timing of the investment was at odds with the IRP filing but 

justified, the Company should include in its IRP filing explanation regarding the timing, 

the reasons such construction was started without the proper regulatory review, and the 

analysis conducted before starting construction. This analysis must include 

consideration of alternatives. 

In Staff’s final comments on PacifiCorp’s Action Item 8b related to pollution control 

investments at Hunter Unit 1, Staff explained that the function of the IRP is to evaluate 

planned investment decisions, not historic investment decisions and that historic 

investment decisions should be evaluated in a general rate case. Staff will only 

recommend the Commission acknowledge investments that have been presented to the 

Commission on a timely planning basis. An investment is not timely if, at the time the 

Commission is developing its acknowledgement order, the Commission’s options have

been substantially limited due to timing. It is Staff’s position that when a decision is 

brought before the Commission in an IRP, all reasonable options need to be available to 

the Commission, including delaying an investment or forgoing an investment. 

Staff needs to clearly understand projected timing of compliance alternatives, including 

key milestones, procurement times and decision points. As part of future IRPs, the 

Company should provide documentation of timelines and key decision points for 

expected pollution control options and any major investments. Additionally, as Staff 

spelled out in our opening and final comments, tables should be provided in the next 

IRPs detailing major planned expenditures with estimated cost in each year for each 

generating facility under different scenarios. These tables should be similar to 

PacifiCorp’s 2013 IRP Volume I, Table 8.7.
Staff Report LC 57

March 4, 2014

Page 16

In addition, Staff proposes an additional action item whereby the Company will come 

before the Commission quarterly to provide updates on the status of environmental 

compliance requirements, lawsuits, investments and major capital expenditures at the 

Company’s coal plants. Staff recommends the addition of the following action items:

Proposed New Action Item 8i – Timelines

As part of future IRPs, the Company shall provide documentation of timelines 

and key decision points for expected pollution control options.

Proposed New Action Item 8j – Planned expenditures

As part of future IRPs, the Company shall provide tables detailing major planned 

expenditures with estimated cost in each year for each generating facility, under 

different modeled scenarios.

Proposed New Action Item 8k – Quarterly updates

Following the issuance of the final Commission order in this IRP, starting in the 

third quarter of 2014, the Company shall come before the Commission at a public 

meeting and make quarterly updates on coal plant compliance requirements, 

legal proceedings, pollution control investments, and other major capital 

expenditures at the Company’s coal plants.

2.4 Water Issues

Other Parties’ Positions

NRDC in comments submitted August 9, 2013, identified that a July 2013 U.S. 

Department of Energy Report identified power system vulnerabilities to climate change 

phenomenon including water availability, heat and drought, particularly in the 

Southwestern United States with which NRDC indicates the PacifiCorp system is 

interconnected. NRDC suggests these climate change factors were not considered in 

PacifiCorp’s analysis and “should raise questions, for purposes of OPUC’s 

acknowledgement of the draft IRP, whether PacifiCorp customers should be at risk for 

company investment decisions that may result in significant future stranded costs.”12

ODOE points out that in this IRP, PacifiCorp included costs associated with one 

significant federal rulemaking (cooling water intakes under Clean Water Act Section 

316(b)) but not for another (new industry toxic discharge guidelines) that is scheduled to 

conclude in 2014. ODOE makes the following recommendations related to water in its 

final comments:

 

12 NRDC Comments on PacifiCorp’s 2013 IRP, page 3.
Staff Report LC 57

March 4, 2014

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1. The Commission should require PacifiCorp in future IRPs to report on significant 

water issues associated with plant operations and ways to mitigate water risks. 

The report should include upgrades that are required for reasons other than 

direct federal requirements.

2. The Commission should direct PacifiCorp to incorporate costs of anticipated 

water compliance and management upgrades expected within the next ten years 

into its model.

ODOE also supports PacifiCorp’s decision to incorporate dry cooling as a standard 

measure for new gas units. ODOE points out that in this IRP, PacifiCorp included costs 

associated with cooling water intake guidelines but not for effluent guidelines that are 

likely to be put into effect in 2014.

Company Response

In response, the Company indicates that securing reliable sources of water has been 

part of the Company’s long-term historical development of power generations resources 

and the Company has adopted a strategy of acquiring senior water rights and long-term 

storage rights. PacifiCorp notes that as thermal resources are retired (such as the 

Carbon Plant) or converted to gas (such as Naughton 3) there will be considerable 

reduction in the need for water. The Company proposes that further discussion be held 

with parties in the 2015 IRP public process to determine the form of any water supply 

risk assessments that should be performed. PacifiCorp indicates in the future IRPs it 

will include costs for effluent guidelines. 

Staff Recommendation

Staff appreciates parties’ comments on water issues and supports the Company’s 

proposal that further discussions be held with parties in the 2015 IRP public process to 

determine the form of water supply risk assessments that should be performed.

3. COAL PLANT ACTION ITEMS

3.1 Selective Catalytic Reduction at Jim Bridger Units 3 and 4

Action Item 8c calls for installing SCR pollution control equipment at Bridger Units 3 and 

4 by the end of 2015 and 2016, respectively as required by the State of Wyoming and 

the U.S. Environmental Protection Agency.

Staff Position

Staff believes there are deficiencies in the Company’s analysis for Bridger, and expects 

to see more comprehensive analysis for coal plant investments going forward. Staff 
Staff Report LC 57

March 4, 2014

Page 18

conducted an analysis of information provided by the Company for Bridger, which 

included portfolio analysis results from the Company’s System Optimizer model and 

PaR. The Company provided results for early shutdown under two different sets of 

retirement dates in exchange for not installing SCR equipment at Bridger 3 and 4. Staff 

also performed our own analysis of the economics of Bridger units 3 and 4 using a 

spreadsheet model developed by Staff. 

Staff recognizes the importance of the Bridger facility to PacifiCorp’s system in that it 

provides a number of ancillary services to PacifiCorp’s system, including voltage 

regulation, frequency regulation and response, energy imbalance correction and 

operating reserves to PacifiCorp’s balancing authorities. Based on the data provided by 

the Company in this IRP, Staff believes additional alternative analysis for Bridger would 

not have likely changed the outcome for Bridger because there are other coal plants in 

PacifiCorp’s fleet that are better candidates for shutdown or gas conversion.

 

Other Parties’ Positions

CUB suggests that PacifiCorp’s early shutdown analysis is flawed and that without 

better analysis, it is not clear whether phasing out the plants would be cost effective or 

not.13 CUB’s position is that PacifiCorp is failing to meet its burden to prove Hunter 1, 

Bridger 3 and Bridger 4 environmental compliance investments are least-cost/least risk 

and therefore there is not sufficient evidence on which to base acknowledgement of 

these investments.

RNP recommends the Commission not acknowledge pollution control investments at 

Jim Bridger 3 and 4, because generally investing in coal units is not reasonable under 

scenarios with low natural gas costs and/or stringent CO2 regulation and lack of 

analysis regarding alternative compliance proposals. 

NWEC recommends the Commission not acknowledge any action item related to coal 

resource investments in this IRP because a) the Company continues to underestimate 

the cost and risk of continued reliance on coal generation, b) the Company failed to 

analyze several coal units that should have been evaluated in this IRP, and c) generally 

the 2013 IRP fails to comply with IRP guidelines 4.g. and 8.a.14

Sierra Club points out that Bridger 3 and 4 are in active construction now. Sierra Club 

recommends the Commission not acknowledge Bridger 3 and 4 because 

acknowledgement of IRP items is for planning purposes and the IRP cannot be treated 

 

13 LC 57 CUB Opening comments filed August 22, 2013.

14 Because NWEC’s argument applies to all coal resource action items, NWEC’s argument and 

PacifiCorp’s response are only documented in this section and not repeated for each coalrelated action item.
Staff Report LC 57

March 4, 2014

Page 19

as a predetermination docket or Certificate of Public Convenience & Necessity (CPCN) 

because the Company is not being held to the same standards of a rate case or CPCN. 

Sierra Club participated in two dockets in other states that looked at the Bridger 3 and 4 

investments15 and did not find analysis produced by the Company satisfactory or 

reasonable. Sierra Club points out that retirement of Bridger 3 and 4 would free up 

significant transmission capacity, potentially allowing the Company to defer near-term 

planned investments.16

Sierra Club is concerned that the Company’s decision to maintain Bridger 3 and 4 is 

largely traceable to the Company’s requirement to collect sufficient remediation funds to 

close the Bridger Surface Mine. Sierra Club supports this assertion by saying that the 

Company’s analysis of the retirement of Bridger 3 and 4 assumes that the Company 

would close the Bridger Surface Mine immediately, thus shifting coal mine remediation 

costs into the near future instead of well after the assumed plant closure decades away, 

whereby the Company realizes a higher net present value. 

Company Response

PacifiCorp states that its analysis of the proposed Bridger 3 and 4 pollution control 

investments is comprehensive, covering viable compliance alternatives across a range 

of natural gas and CO2 price assumptions. PacifiCorp also points out that it performed 

an analysis of phase-out scenarios assuming Bridger 3 and 4 continue to operate 

without the SCR investment through 2020 and 2021, respectively and also at Staff’s 

request, through 2022 and 2023, respectively. PacifiCorp maintains that these analyses 

show that SCR installations at Bridger 3 and 4 are the lowest cost alternative. 

PacifiCorp responds to NWEC’s general complaint about PacifiCorp’s overall coal 

analysis (that the Company underestimates the risk of continued reliance on coal 

generation, does not adequately address the full range of future regulations, and did not 

analyze several coal units that should have been analyzed) by pointing out that it 

analyzed a wide range of CO2 price scenarios in the portfolio development process, 

included costs to comply with prospective future regulations on coal combustion 

residuals and cooling water intake structures, and analyzed potential future Regional 

Haze compliance requirements. The Company further says that it included financial 

analysis of coal unit investments requiring near term actions and evaluated longer-term 

compliance requirements among all owned coal units in the portfolio development 

process and therefore fully complied with Oregon IRP Guidelines.

 

15 Wyoming docket 20000-418-EA-12 and Utah docket 12-035-92.

16 LC 57 Sierra Club final comments, page 17.
Staff Report LC 57

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In response to RNP, PacifiCorp points out that its analysis supports the SCR 

investments as the lowest cost alternative even when high CO2 prices are paired with 

either base case or high natural gas prices. 

In response to Sierra Club’s assertions that PacifiCorp failed to take into consideration 

transmission cost savings that would result from early retirement at Bridger, PacifiCorp 

asserts the Windstar to Populus Energy Gateway transmission project investment 

decision is independent of the decision to install SCR equipment at Bridger 3 and 4 and 

that there are other substantial benefits of this project, including reliability benefits, 

increase access to wind and other resources and more efficient use of the transmission 

system. 

Relative to Sierra Club’s assertions that PacifiCorp’s Bridger investments are motivated 

by accelerated Bridger mine reclamation cost recovery, PacifiCorp states that for each 

potential compliance alternative, assumptions, including mine reclamation cost 

assumptions, are uniquely developed. The Company claims that assumed reclamation 

costs are consistent with expected changes in the mine plan if the SCRs are not 

installed. 

Staff Recommendation

Staff performed analysis as described above related to the proposed SCR investments 

at Bridger Units 3 and 4. Staff sent a data request to the Company and confirmed that 

Bridger 3 and 4 are currently under construction and that as of February 7, 2014, nine

percent of the total project cost has been spent. In the future, Staff expects the 

Company to bring action items before the Commission well in advance of beginning of 

construction. Notwithstanding, Staff recommends the Commission acknowledge Action 

Item 8c for the SCR investments at Bridger 3 and 4 in 2015 and 2016, respectively. 

3.2 Low NOx burner and Baghouse at Hunter Unit 1

Action Item 8b is to complete the installation of a baghouse and low NOx burner (LNB) 

at Hunter Unit 1 by the end of 2014. 

Staff Position

According to PacifiCorp’s response to staff data request OPUC 280, as of 

December 21, 2013, the baghouse project at Hunter Unit 1 is approximately 50 percent 

complete and the LNB is approximately 20 percent complete. Staff asked the Company 

about the cost and feasibility to delay existing construction commitments at Hunter for 

six or twelve months.17 The Company responded that delaying would result in 

Engineering, Procurement and Construction (EPC) contract cost claims and all other 

planned major maintenance contracts and work scope currently in place to support the 

 

17 OPUC DR 280, part (e)
Staff Report LC 57

March 4, 2014

Page 21

outage planned to install the equipment. The Company indicated the delay would also 

trigger significant concern, expenditure of resources, loss of project execution focus and 

productivity, loss of competitive market credibility and significantly increase contractor 

performance risk and cost. 

PacifiCorp did not reference any pollution controls at Hunter 1 in its 2011 IRP, which 

would have been the appropriate avenue to raise awareness about the Hunter 1 

pollution control requirements. At this point, it is clear that the Company would have 

significant trouble reversing its decision to move forward with the Hunter investments 

and therefore the Commission is being put in a difficult situation by being asked to rule 

on something that is already substantially complete. Staff recommended the 

Commission not acknowledge the Hunter 1 pollution control investments.

Other Parties’ Positions

RNP recommends the Commission not acknowledge pollution control investments at 

Hunter 1, for the same reasons it does not recommend acknowledgement of 

investments at Bridger 3 and 4; because a) generally investing in coal units is not 

reasonable under scenarios with low natural gas costs and/or stringent CO2 regulation 

and b) there is a lack of analysis regarding alternative compliance proposals. 

Sierra Club does not support the acknowledgement of Action Item 8b because it 

contends that a) the baghouse and LNB are not required at this time because the EPA 

has not made a final best available retrofit technology (BART) determination for the 

state of Utah, b) the Company’s investment decision in May 2012 was premature and 

did not take into account further likely expenses, including an SCR, and c) the 

Company’s modeling results in this IRP did not return robust results in support of this 

level of detail. Additionally, Sierra Club asserts that to the extent that an 

acknowledgement is akin to finding of prudent planning, the Company has not made 

such a showing in this IRP docket.

Sierra Club points out limitations and inconsistencies in PacifiCorp’s financial analysis 

related to Hunter Unit 1. Namely, when the Company looked at the analysis based on 

what was known in May 2012, it did not look at the case of a 2018 SCR, even though in 

June 2012, Sierra Club argued before the Commission that the Company should have 

at least considered the risk the SCR would be required by 2017. In this way, Sierra 

Club contends that PacifiCorp missed a critical review. Sierra Club also faults the 

Company for only performing analysis under base assumptions and becuase it did not 

conduct reasonable sensitivities on gas and CO2 prices. 

Lastly, Sierra Club provides confidential details as to why the analysis supporting the 

investment at Hunter 1 is, as they define it “erroneous and misleading, or shows that the 
Staff Report LC 57

March 4, 2014

Page 22

System Optimizer model is extremely unstable and unsuited for these types of 

decisions.”18 

Company Response

PacifiCorp disagrees with Staff that action item 8b is not appropriate because 

construction has already begun, because:

1) Hunter 1 baghouse and LNB are not yet in service

2) The Planned in-service date for the baghouse and LNB equipment falls within 

the twenty-year planning period of the IRP

3) Nothing in the IRP Guidelines prohibits the Commission from acknowledging 

action items that are expected to be completed within the planning period, 

even if work has already begun.

PacifiCorp responds to RNP’s assertion that base case CO2 prices are no longer 

reasonable given the current policy environment and states that the Commission should 

review the environmental investment analysis under a high CO2 price scenario, by 

pointing out that the Hunter Unit 1 financial analysis included in Confidential Volume III 

of the 2013 IRP shows that the baghouse and LNB investments are the lowest cost 

alternative when high CO2 prices, beginning in 2018, are assumed. 

PacifiCorp responds to Sierra Club’s assertions that the baghouse and LNB are not 

required at this time because EPA has not approved the Utah SIP for NOx and 

particulate matter (PM) by pointing out that Utah Department of Environmental Quality 

(DEQ) confirmed in a letter that the requirements are enforceable under state law, 

irrespective of EPA’s action.

PacifiCorp responds to Sierra Club’s assertions that the Company’s modeling is 

erroneous and unstable by stating that PacifiCorp’s modeling is not erroneous and 

unstable but rather that changes in system costs between scenarios can influence the 

resource mix and cause changes to system energy and system costs.

PacifiCorp responds to RNP’s position by pointing out that its analysis supports the 

baghouse and LNB investments as the lowest cost alternative; even when high CO2 

prices are assumed and even when prospective future SCR costs are accelerated to 

2018. PacifiCorp asserts that the 2013 IRP was filed consistent with Oregon IRP 

Guidelines, and PacifiCorp requests that the Commission acknowledge Action Item 8b.

PacifiCorp maintains that it modeled compliance alternatives for Hunter Unit 1 

consistent with current regulatory requirements enforceable in the state of Utah and that 

 

18 LC 57 Sierra Club final comments, page 17.
Staff Report LC 57

March 4, 2014

Page 23

the 2013 IRP was filed consistent with Oregon IRP Guidelines and therefore Action Item 

8b should be acknowledged by the Commission.

Staff Recommendation

Staff is not persuaded by the Company’s response. Staff continues to recommend the 

Commission not acknowledge Action Item 8b because the project is under construction 

and substantially complete and the Company failed to provide evidence explaining the 

circumstances that prevented its inclusion in previous IRPs. In the future, the Company 

should bring investments decisions to the Commission in IRPs prior to beginning 

construction to the extent possible.

3.3 Gas Conversion at Naughton Unit 3

Action Item 8a is to continue permitting in support of natural gas conversion at 

Naughton Unit 3, issue an RFP to pursue gas transportation to the plant, and issue an 

RFP for engineering, procurement and construction. 

Staff Position

In Staff’s final comments, we point out that in Action Item 8a, the Company is currently 

asking for acknowledgment of seeking a permit and issuing and RFP for converting 

Naughton 3 to gas by 2018. Staff is recommending acknowledging Action Item 8a, the 

permitting and RFP for gas conversion at Naughton Unit 3, but at this time would not 

support actual gas conversion because of the Company’s current resource position and 

because insufficient analysis has been provided, particularly related to the option of 

shutting down Naughton Unit 3 rather than converting it to gas and how that would 

impact the projected load resource balance. 

Other Parties’ Positions

Sierra Club does not object to acknowledgement of the Naughton 3 gas conversion on 

the grounds that this particular issue seems to have been vetted thoroughly by 

interveners in Wyoming docket 11-035-200.

RNP recommends the commission acknowledge action item 8a pertaining to natural 

gas conversion at Naughton 3 but does cite specific reasons for its recommendation.

Company Response

In response to Staff’s position that although the 2013 IRP indicated gas conversion was 

lower cost than installing and SCR and baghouse in 2015, there is insufficient analysis 

to support natural gas conversion in 2018, PacifiCorp claims that deferring the gas 

conversion to 2018 only improves the economics of gas conversion. PacifiCorp does 

not support Staff’s proposed addition to Action Item 8a that would require the Company 
Staff Report LC 57

March 4, 2014

Page 24

to seek acknowledgement of the 2018 gas conversion in the 2015 IRP, but says it will 

update the Commission and parties on the status of the Naughton Unit 3 gas 

conversion project in the 2015 IRP. 

Staff’s Recommendation

Staff agrees with the Company that gas conversion in 2018 would likely be more cost 

effective than gas conversion in 2015, but contends that a) gas conversion is not the 

only viable option for Naughton 3 and b) the Company should take a second look at the 

option of shutting down Naughton 3, and c) before starting construction, the options for 

Naughton 3 should be revisited with updated gas, load, carbon and energy price 

expectations. Staff pointed out in our final comments, that PacifiCorp’s models show 

Naughton 3 is minimally dispatched in the cases where it is assumed to convert to gas 

in 2015 and therefore, changes to load forecasts and gas prices between the time loads 

were developed for the 2013 IRP models and what will be used for the 2015 IRP, could 

impact the economics of alternatives at Naughton 3 including gas conversion or 

shutdown. 

Also, Staff feels it is important to point out that the planned gas conversion of Naughton 

3 is an example of regulatory flexibility which allows the Company to trade current 

emissions for long run emissions savings. The relevant portion of the initial Wyoming 

Regional Haze SIP which was approved by the EPA required SCR and baghouse on 

Naughton 3 by the beginning of 2015. All of PacifiCorp’s modeling in the 2013 IRP is 

based upon the required retrofit being installed or the unit being converted or retired 

along this 2015 timeframe. However, Action Item 8a asks the Commission to 

acknowledge a permit application to its Wyoming regulators to operate Naughton 3 as a 

coal unit without an SCR and baghouse through 2017 in violation of the initial EPA 

approved SIP for three years. The Company is trading three additional years of coal 

operations and higher emissions for gas conversion afterwards that achieves long run 

emissions savings. PacifiCorp obviously felt its Wyoming regulators and EPA would be 

amenable to this plan and the recently finalized EPA FIP for Wyoming is validation this 

type of inter-temporal trade-off is possible as the 2018 conversion was part of the 

finalized EPA requirements. Staff agrees with this Boardman-like approach and agrees 

wholeheartedly with the Company that deferring the gas conversion improves the 

economics of the conversion. This is exactly the reason Staff insists this type of intertemporal trade-off needs to be considered for all substantial coal fleet investments.

Staff recommends Action Item 8a be acknowledged as modified below:

Action Item 8a. - Naughton Unit 3

– Continue permitting and development efforts in support of the Naughton Unit 3 

natural gas conversion project. The permit application requesting operation on 
Staff Report LC 57

March 4, 2014

Page 25

coal through year-end 2017 is currently under review by the Wyoming 

Department of Environmental Quality, Air Quality Division. 

– Issue a request for proposal to procure gas transportation for the Naughton plant 

as required to support compliance with the conversion date that will be 

established during the permitting process.

– Issue an RFP for engineering, procurement, and construction of the Naughton 

Unit 3 natural gas retrofit as required to support compliance with the conversion 

date that will be established during the permitting process.

– Evaluate the Naughton Unit 3 investment decision in the 2015 IRP with updated 

analysis including the shutdown versus conversion options.

3.4 Cholla Unit 4 Regulatory Compliance

Action Item 8d is for the Company to continue to evaluate compliance strategies for 

Cholla Unit 4 and provide analysis regarding compliance alternatives in the 2013 IRP 

Update. 

In Staff’s final comments, we point out that Cholla is one of the most expensive of 

PacfiCorp’s coal plants at that in four of the core cases modeled in this IRP and in one 

sensitivity case, PacifiCorp’s models demonstrate that it is economical for Cholla 4 to 

shut down in 2017. Staff also expressed concerns about the timing of the Cholla 4

investments (SCR equipment required by the end of 2017) and the fact that no analysis

on Cholla 4 was included in this IRP. 

Sierra Club states that its primary concern with Cholla Unit 4 was that the Company’s 

analysis showed it was non-economic by 2025 in the base scenario and non-economic 

by 2017 in a low gas/high CO2 price scenario. Sierra Club contends the unit would be 

unlikely to pay off its SCR investment over a reasonable amortization period and 

therefore, recommends the Company explore closing the unit. Sierra Club believes that 

a rigorous analysis of Cholla 4’s economics would not support an SCR retrofit. Sierra 

Club recommends that the Commission should set a date certain, preferably within the 

next four months, by which the Company should file a Coal Investment docket for 

Cholla 4. 

Company Response

PacifiCorp indicates it will provide an update on Cholla in the 2013 IRP Update and 

therefore, recommends the Commission acknowledge Action Item 8d as filed. 

Staff Recommendation

Staff recommends the Company bring the Cholla 4 analysis back to the Commission 

through a special IRP update. Parties and the Commission can consider the investment 
Staff Report LC 57

March 4, 2014

Page 26

at that time. Staff recommends Action Item 8d for Cholla Unit 4 be acknowledged as 

modified below: 

Action Item 8d. - Cholla Unit 4

Continue to evaluate alternative compliance strategies that will meet Regional 

Haze compliance obligations, related to the U.S. Environmental Protection 

Agency’s Federal Implementation Plan requirements to install SCR equipment at 

Cholla Unit 4. Provide an update of the analysis of Cholla Unit 4 analysis 

regarding compliance alternatives in the 2013 IRP Update in a special 

designated IRP Update within six months of the final order in LC 57 and well 

enough in advance to allow for all potential reasonable pollution control 

alternatives for Cholla to be adequately pursued. 

3.5 Craig and Hayden Coal Plant Investments

SCR technology is planned to be installed at the jointly owned coal plants, Craig and 

Hayden, between 2015 and 2017. PacifiCorp is a minority owner of both plants. There 

are no action items in this IRP related to Craig and Hayden.

In Staff’s final comments, we recommended a new action item 8e that would commit 

PacifiCorp to request acknowledgement of the environmental investments at Craig and 

Hayden within six months of Commission’s determination in this IRP. Staff pointed out 

that in the past the Commission has ruled that even when a company has minority 

ownership in a plant, the Company needs to analyze the possible costs and 

consequences of environmental regulations associated with the joint ownership plant. 

Sierra Club alleges that simply because these units are operated by other parties does 

not alleviate PacifiCorp of its responsibility to ensure that they are economically useful. 

Sierra Club recommends that the Commission require PacifiCorp to produce an 

economic analysis of Craig and Hayden immediately.

Company Response

In the Company’s final comments, PacifiCorp indicated a willingness to review with the 

Commission and parties, through a confidential technical workshop existing analysis on 

the planned Craig and Hayden environmental investments. The Company states that 

assuming the appropriate protections are put in place that restrict the use of information 

presented at the technical workshop, the Company will schedule that workshop within 

three months of the Commission order in this docket. 

Staff Recommendation
Staff Report LC 57

March 4, 2014

Page 27

Staff is amenable to the approach proposed by PacifiCorp in lieu of the specific action 

item related to Craig and Hayden that Staff proposed in our final comments which would 

have required the Company to bring forth an analysis of Craig and Hayden as part of a 

separate coal analysis docket. Staff recommends the addition of the following action 

item:

Proposed new action item 8e.

Within three months of the Commission order in this docket PacifiCorp shall 

schedule a confidential technical workshop to review existing analysis on the 

planned Craig and Hayden environmental investments. 

4. TRANSMISSION

4.1 System Operational and Reliability Benefits Tool (SBT)

 

Background

PacifiCorp engaged in extensive efforts to address the scenario definition of its 2013 

IRP with stakeholders through a public process. The Company developed, in 

consultation with stakeholders, the System Operational and Reliability Tool (SBT) which 

was designed by PacifiCorp for identifying and quantifying transmission benefits not 

captured using traditional IRP analysis tools. In PacifiCorp’s reply comments, 

PacifiCorp notes that it will change how the SBT is applied based on comments 

received at a public input meeting on the SBT.

Parties Position

CUB acknowledges that although it continues to be concerned about the SBT, the 

Company has agreed to separate Customer and Regulatory benefits so that those 

categories will not be included in the cost-benefit ratio calculations. This resolves 

CUB’s primary concern. CUB says they expect the Company to continue to work with 

stakeholders on how it intends to calculate system benefits going forward. 

In our final comments, Staff indicates that we are appreciative that the SBT will continue 

to improve and evolve over time, with stakeholder input.19 

Proposed Action Item 9a describes how within 60 days of filing the 2013 IRP, the 

Company will establish a stakeholder group and schedule workshops to further review 

the SBT as well as for the 2013 IRP Update. The Company did this. The Action Item 

also says that for the 2013 IRP Update, the Company will complete additional analysis 

 

19 LC 57 Staff final comments, page 17.
Staff Report LC 57

March 4, 2014

Page 28

of the Energy Gateway West Segment D that evaluates the staging implementation of 

Segment D by sub-segment. Finally, Action Item 9a states that in preparation for the 

2015 IRP, the Company will continue to refine the SBT for Energy Gateway Segment D 

and develop SBT analyses for additional Energy Gateway Segments.

Staff Recommendation

Staff is appreciative that the Company is engaging with stakeholders and that the SBT 

will continue to be reviewed and modified. However, Action Item 9a is not a specific 

resource action and therefore does not require acknowledgement by the Commission. 

4.2 Energy Gateway Permitting – Action Item 9b

Background and Staff Position

The Company’s proposed Action Item 9b relates to permitting actions for Poplulus to 

Windstar (Segment D), Populus to Hemingway (Segment E), Aeolus to Mona (Segment 

F), and West of Hemingway (Segment H). The Company provided a preliminary SBT 

analysis to quantify the benefits of Segment D, however, as stated above, the Company 

will be making changes to how the SBT is applied. Regarding Segments E, F, and H, 

Staff recognizes that there is uncertainty in developing these segments until their 

anticipated in-service dates. However, uncertainty should not hinder the Company’s 

efforts to continue exploring the projects in light of the preliminary benefits of these 

segments. 

Other Parties’ Positions

Sierra Club states that it has been involved in two CPCN dockets that questioned 

transmission planning and it remains unclear to Sierra Club why the Company intends 

to permit and construct additional transmission in Wyoming. Sierra Club points out that 

in the 2011 IRP, the Company determined it was cost effective to build 2,100 MW of 

new wind projects from 2018-2029. Consequently, PacifiCorp planned new 

transmission to carry wind energy from eastern Wyoming to load centers. Sierra club 

points to the 2011 IRP that said “the Company’s planned transmission additions reflect 

its belief that state and federal energy policies will continue to push toward renewable 

and low-carbon resources”

20 and that renewable energy underlies the transmission 

footprint assumed in the preferred portfolio. Sierra Club points out that in the 2013 IRP, 

these expected wind resources were decreased from 2,100 MW to 650 MW, with no 

new wind coming on until 2024. Despite this, the Sierra Club points out the Company 

continues to move forward with permitting. 

 

20 LC 57 Sierra Club’s final comments, page 22, referencing the PacifiCorp’s 2011 IRP, page 

48. 
Staff Report LC 57

March 4, 2014

Page 29

Sierra Club also argues that neither the 2011 or 2013 IRP set out a compelling reason 

why ratepayers should be funding billions of dollars in transmission between existing 

resources. Sierra Club points out that in the Bridger CPCNs, the Company identified 

only one transmission constraint between eastern Wyoming and the Company’s load 

centers that binds occasionally but does not seem to merit a new interstate transmission 

line. Two other Companies are seeking to build transmission from eastern Wyoming to 

load centers, both drawing wind from north of Cheyenne to Las Vegas via Utah. Sierra 

Club says it is unclear if PacifiCorp wants to build transmission in hopes it can justify 

wind in a future IRP, or if it hopes to use ratepayers and existing infrastructure to 

outpace two competitors to market.21

In general Sierra Club says it opposes the Company’s efforts to build new transmission 

into eastern Wyoming until the Company backs its investments with a commitment to 

acquire renewable resources in the region. 

Company Response

In its final comments, the Company does not oppose Staff’s recommendations on 

Action Item 9b. PacifiCorp will continue to refine the SBT in preparation for the 2015 

IRP but notes that there may be limitations to the analysis that can be performed at the 

time of the 2015 IRP. The Company further notes that the in-service dates for 

Segments D, E, F and H are several years in the future. PacifiCorp notes, in response 

to Sierra Club’s comments, that the Company is not asking for acknowledgment of the 

Energy Gateway projects, but rather identifies near-term permitting activities required to 

maintain the options to move forward with Energy Gateway projects as supported in 

future planning activities. 

Staff’s Recommendation

Staff recommends acknowledging the Company’s Action Item 9b with the modifications 

shown below:

Proposed modified Action Item 9b. 

Continue permitting Segments D, E, F, and H until PacifiCorp files its 2015 IRP, 

when SBT analyses for these segments will be performed.

Continue permitting for the Energy Gateway transmission plan, with near term 

targets as follows:

– Segment D, E, and F, continue funding of the required federal agency 

permitting environmental consultant as actions to achieve final federal permits.

 

21 LC 57 Sierra Club final comments, page 22.
Staff Report LC 57

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– Segment D, E, and F, continue to support the federal permitting process by 

providing information and participating in public outreach projected through the 

next 2 to 4 years.

– Segment H Cascade Crossing, complete benefits analysis in 2013.

– Segment H Boardman to Hemingway, continue to support the project under the 

conditions of the Boardman to Hemingway Transmission. Project Joint Permit 

Funding Agreement, projected through 2015.

4.2 Sigurd-to-Red Butte (S2RB)

Background

In action item 9c the Company is seeking acknowledgment of completing construction 

of the Sigurd-to-Red Butte (S2RB) 345 kilovolt Transmission Line per plan. The 

Company sought acknowledgement of the line in the 2011 IRP. Instead of the 

Commission acknowledging the line in the 2011 IRP, a new action item number 10 was 

developed as follows:

In the scenario definition phase of the IRP process, the Company will address 

with stakeholders the inclusion of any transmission projects on a case-by-case 

basis.

- Develop an evaluation process and criteria for evaluating transmission 

additions.

- Review with stakeholders which transmission projects should be included and 

why.

- Based on the outcome of these steps, PacifiCorp will provide appropriate 

transmission segment analysis for which the Company requests 

acknowledgment (including Wallula to McNary and Sigurd to Red Butte).

Other Parties’ Positions

ICNU points out that the Company has already begun construction on the Sigurd-to-Red 

Butte transmission line.22 ICNU asserts that the goal of an IRP is to seek 

acknowledgement of the Company’s plans to meet expected loads based on its 

expected costs, risks and uncertainties. ICNU also points out that concerns have been 

raised in Oregon about whether PacifiCorp’s transmission plans adequately account for 

expected future conditions and in Washington regarding whether the Company is 

inappropriately focusing on building transmission rather than alternatives, including 

smart grid technology.23 ICNU suggests the Commission can avoid any disputes 

regarding transmission issues by declining to acknowledge Sigurd-to-Red Butte on the 

 

22 LC 57 ICNU final comments, page 7.

23 LC 57 ICNU final comments, page 7.
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grounds that the Company has already decided to build and began construction without 

the required input and consideration.

Sierra Club mentions that it takes no position on the Sigurd-to-Red Butte transmission 

line and adds that “At this time, Sierra Club does not specifically contest the 

acknowledgement of the Sigurd-to-Red Butte transmission line.”24

RNP recommends acknowledgement of the Sigurd-to-Red Butte transmission line. In 

it’s opening comments filed on August 23, 2013, RNP commends PacifiCorp for the 

ingenuity of its expanded transmission analysis in this IRP, particularly related to the 

fact that multiple transmission topologies were modeled for each scenario. RNP also 

commends the Company on its System Benefits Tool.25 

Company Response

PacifiCorp says that the S2RB transmission line is necessary to provide safe and 

reliable service to customers and to meet expected and forecasted customer energy 

demand and that it improves compliance with regulatory requirements and reliability 

standards. The Company indicates that it disagrees with ICNU’s interpretation that 

Action Item 9c does not comply with Oregon IRP Guidelines. The Company states: 

“The Sigurd-to-Red Butte transmission line has not yet been placed in service, 

falls within the twenty year planning period of the IRP, and nothing in the Oregon 

IRP Guidelines prohibits the Commission from acknowledging action items that 

are expected to be completed within the planning period, even if work on the 

action item has already begun.”

In response to ICNU’s assertion that the Company decided to build and began 

construction on the S2RB transmission line without the required input and 

consideration, the Company points out that the transmission line in question has been 

included in numerous public proceedings including the permitting process and IRP 

processes. PacifCorp points out that the Sigurd-to-Red Butte line was included as a 

segment of the Energy Gateway project as early at the 2008 IRP, filed in March 2009 

and that the project was also included in the 2011 IRP and 2011 IRP Update. In each 

of these IRPs, opportunities for public input were provided. The Company states that 

the project is necessary to “provide safe and reliable service to customers and to meet 

expected and forecasted customer energy demand.”26 The Company claims in its final 

comments that the project benefits the local areas where it is constructed and the wider 

interconnected transmission system. PacifiCorp asserts that the line allows the 

 

24 LC 57 Sierra Club final comments, page 18.

25 RNP opening comments in LC 57, page 10-11.

26 LC 57 PacifiCorp’s final comments, page 23.
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Company to comply with mandatory Federal Energy Regulatory Commission (FERC), 

North American Electric Reliability Corporation (NERC), and Western Electricity 

Coordinating Council (WECC) reliability obligations. 

Staff Recommendation

For the reasons stated in Staff’s final comments, we continue to recommend 

acknowledgement of the S2RB transmission line. Staff recognizes that S2RB is 

currently under construction and based on the Company’s response to Staff data 

request 296, is 53% complete as of January 31, 2014.

27

 PacifiCorp requested 

acknowledgment of S2RB in the 2011 IRP. Rather than acknowledge the investment in 

that IRP, modified action item number ten was developed and included in the final 

Commission Order. Action Item 10 requires that PacifiCorp provide appropriate 

transmission segment analysis for segments the Company is requesting 

acknowledgement for, including S2RB. Therefore, in summary, even though S2RB is 

currently under construction, in the 2011 IRP the Company was asked to bring the 

investment back with appropriate transmission segment analysis.

Staff reiterates that because the primary beneficiaries are the Company’s network 

transmission customers (i.e., PacifiCorp Energy, Utah Associated Municipal Power 

Systems (UAMPS), and Deseret Generation and Transmission Cooperative (DG&T)), 

and specifically their loads in southwest Utah, the allocation of costs should be 

commensurate with the benefits received by each network transmission customer or 

state. This may be addressed in the appropriate venue, such as multistate allocation 

processes and general rate proceedings.

5. Demand Side Management (DSM)

5.1 Class 2 DSM

Background

Action Item 7a is to acquire 1,425 – 1,876 GWh of cost-effective Class 2 energy 

efficiency resources by the end of 2015 and 2,034 – 3,180 GWh by the end of 2017. 

Action Item 7a also contains multiple specific actions the Company plans to implement 

to achieve those targets. Class 2 DSM includes energy efficiency measures such as 

efficient lighting, motors, air conditions, insulation, windows, etc.

 

27 OPUC Staff Data Request 296
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PacifiCorp’s Action Item 7a contains a range of conservation to achieve by the end of 

2015 and 2017.28 

Staff’s Position

As Staff understands, the low end of that range relates to the amount of conservation 

selected by PacifiCorp’s model in the preferred portfolio EG2-C07 and the high end 

corresponds to the amount of conservation selected by PacifiCorp’s model in a case 

designed to test the effects of accelerating DSM, case EG2-C15. Because the detailed 

7a action item elements have purportedly been accelerated over what the Company 

otherwise would have done, Staff expects the Company to achieve conservation higher 

than the low end of the range and potentially up to the high end of the range. Staff 

expects the Company to aggressively pursue accelerated DSM in all states. 

Staff is concerned that PacifiCorp exhibited a pattern of serially delaying or cancelling 

DSM programs that were part of acknowledged action items in past IRPs without 

evaluating the long run revenue requirement impacts. Staff notes four specific cases 

that are outlined in the following table. Staff includes a summary of the current status of 

each program and the impact to ratepayers of the delay or cancellation.

Program Status Impact

Small Commercial DSM 

program

Delayed, now happening Forgone benefits of 

accelerated DSM

Residential instantaneous

efficiency measures

Delayed, now happening Forgone benefits of 

accelerated DSM

Special Contract Customers 

EE29

Delayed - To be 

reconsidered in the future 

contract negotiations 

company by company

Forgone benefits of 

accelerated DSM and 

uncertainty whether energy 

savings will be achieved

120 MW Demand Response Cancelled PAC’s model shows 

cheaper to purchase power 

at peak; impact is lower 

cost to customers

 

28 Action Item 7a says the Company will acquire between 1,425 – 1,876 gigawatt hours (GWh) 

of cost effective Class 2 energy efficiency resources by the end of 2015 and 2,034 to 3,180 

GWh by the end of 2017.

29 PacifiCorp didn’t follow through on an action item from the last IRP to pursuing energy 

efficiency with special contract interruptible customers. One reason for this is that PAC focuses 

on capacity planning rather than energy planning, and interruptible customers are already a 

capacity resource. PacifiCorp is planning to explore energy efficiency opportunities in the next 

round of contract renegotiations with these customers. 
Staff Report LC 57

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Staff recommends the Company provide twice yearly updates to the Commission on 

DSM activities outside Oregon. Updates will keep the Company accountable to DSM 

IRP targets and provide an opportunity for the Commission, Staff and stakeholders to 

provide feedback when they deviate. Staff is also specifically asking to be kept up to 

date on negotiations related to energy efficiency opportunities as negotiated with special 

contract customers. 

Included in action item 7a is the following statement: 

Include in the 2014 conservation potential study an analysis testing assumptions 

in support of accelerating acquisition of cost-effective Class 2 DSM resources, 

and apply findings from this analysis into the development of candidate portfolios 

in the 2015 IRP.

In discussions with the Company it appears that this study is intended to be a generic 

study of accelerating DSM and costs of doing so, but to the extent it is generic and not 

specific to PacifiCorp’s service area and customers, the results will not be meaningful. 

Therefore, Staff recommends that rather than conducting a generic investigation the 

Company have an implementation study performed that looks specifically at the ability 

and cost to accelerate DSM programs in the Company’s service territory outside 

Oregon. The resulting information should be used as the basis for the next IRP. 

Finally, it has been difficult to ascertain how DSM targets in each IRP compare to one 

another. In the past the Company has expressed DSM cumulative targets for certain

years and not others. Sometimes DSM numbers are expressed in GWh while other 

times they are expressed as MW. This has led to confusion and difficulty in comparing 

across IRPs. Staff recommends that going forward, yearly DSM acquisition targets be 

provided in a consistent basis, in both GWh and MW for each year in the planning 

period, by state.

Other Parties’ Positions

CUB maintains that Oregon’s DSM targets are more aggressive than the other states, 

because Energy Trust operates programs in Oregon. CUB provided a table that shows 

that in terms of DSM as a percentage of total forecasted load, Oregon’s DSM is higher 

than other states’ through at least 2018. CUB points out that the primary difference 

between the Oregon forecast and the forecast for other states relates to who did the 

assessment. In Oregon it was Energy Trust and for other states it was CADMUS. 

CUB says that the Company has room to consider more Energy Trust-comparable 

programs in other states in order to improve its DSM. 

In CUB’s initial comments, it makes that point that even though the Company is 

proposing action items that may potentially accelerate DSM, it is not clear what kind of 
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effects the accelerated DSM would have on the chosen scenario. Because accelerated 

DSM is not included in the Company’s preferred portfolio (case EG2-CO7a) it is 

unknown what kind of impact accelerated DSM would have on front office transactions 

and other resources. 

In its initial comments CUB also points out that the Company admits that cases EC1-

C15 and EG2-C15 “yield the highest ranking risk adjusted net PVRR.”30 

Notwithstanding this high ranking, the Company did not prioritize these portfolios 

because it felt that it did not have either strong evidence to demonstrate the true 

acquisition costs for DSM or that the revised ramp rate assumptions would be 

achievable.31

CUB expressed concern about the implications of the Company rejecting a least-cost 

scenario because of the uncertainties associated with DSM and points out that 

PacifiCorp, in its 2013 IRP, explains that it is capable of exceeding its Class 2 DSM 

acquisition goals by at least 29% or 242,438 MWh. CUB questions why the Company is 

not pursuing accelerated DSM in this case if it has historically demonstrated that it 

possesses the ability to achieve more energy efficiency than forecasted. CUB is 

disappointed that PacifiCorp “apparently failed to consider its own historical energy 

efficiency results when deciding not to pursue an accelerated DSM scenario.” 

CUB is asking that the Commission not acknowledge the DSM section of PacifiCorp’s 

IRP. 

NWEC makes the point that the Company’s 2013 analysis showed that accelerating 

DSM leads to a lower cost and lower risk portfolio for customers regardless of slow load 

growth and lack of near-term new resource need as demonstrated by the accelerated 

DSM case EG2-C15 ranking as the least cost, least risk portfolio. NWEC proposes that 

the DSM targets in this action item should be set at the levels selected in the 

accelerated DSM portfolio EG2-C15. NWEC maintains a position that PacifiCorp’s 

targets for energy efficiency programs in states other than Oregon are too low and that 

Class 2 DSM targets in the 5-year action plan should not be acknowledged or should be 

increased prior to acknowledgment in the 2013 IRP. 

NWEC, Staff and CUB expressed concern that Oregon ratepayers are funding higher 

levels of cost effective conservation relative to energy efficiency achieved in other states 

and therefore, Oregon rate payers are subsidizing ratepayers in other states, by paying 

 

30 Integrated Resource Plan IRPModeling and Results Update Draft Preferred Portfolio at page 

17 (March 21, 2013). Accessed at: 

http://www.pacificorp.com/content/dam/pacificorp/doc/Energy_Sources/Integrated_Resource_Pl

an/2013IRP/2013IRP_PIM18_PrefPort_3-21-13.pdf

31 LC 57 – 2013 Integrated Resource Plan, Volume I at pg 222.
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for supply-side system costs in equal measure. NWEC specifically recommends the 

Commission require:

1. DSM target should be 1,113,250 MWh of Class 2 DSM (as selected in the 

accelerated DSM case) for the five-year action plan.

2. The Company should regularly report to the Oregon Commission regarding DSM 

through the Company’s territory and should provide quantitative analysis 

supporting any reductions in targets.

The Company should file with the Commission any significant deviation from the 

DSM action plan targets or items and should include an analysis showing why 

these changes are least cost/least risk.

NWEC voiced concern that methodologies used in the company’s resource potential 

conducted by a third-party company, Cadmus, led to an underestimation of the 

achievable technical potential in all states except Oregon. Of particular concern were 

market ramp rate and measure ramp rate calculations. 

ICNU recommends the Commission not acknowledge PacifiCorp’s planned 

conservation investments in its eastern states because they do not fully account for the 

additional conservation that the Company can reasonably obtain. ICNU suggests that 

instead of simply not acknowledging the numbers currently being proposed by 

PacifiCorp, the Commission could acknowledge the accelerated Case EG-C15 as part 

of an overall least cost and least risk portfolio and require the Company to regularly 

report its achieved conservation, including any discrepancies between its target and 

actual conservation. 

Sierra Club, in its preliminary comments filed on August 22, 2013 points out that 

PacifiCorp’s methodology for modeling DSM in its IRP is innovative and has some 

advantages, yet it yields questionable results. Specifically, Sierra Club notes that the 

Company’s model selects a declining amount of incremental DSM each year from 2013 

to 2032. Sierra Club questions this result, noting that few states would claim that they 

are currently at the peak of their energy efficiency potential and that it will only decline 

from here.32 

Company Response

PacifiCorp explains the reasons it did not select accelerated DSM case C15 as the 

preferred portfolio are a) cost assumptions associated with accelerated DSM are 

uncertain, b) ramp rates used were untested, c) CCCTs were not allowed to be selected 

in this portfolio.33 PacifiCorp does not support NWEC’s recommendation that the 

 

32 LC 57 Seirra Club preliminary comments, page 16.

33 PacifiCorp 2013 IRP Volume I, page 222.
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Commission acknowledge DSM targets from case C15 as the preferred portfolio. The 

Company also disagrees with NWEC, ICNU, CUB and Staff’s assertion that Oregon 

customers are funding higher levels of conservation compared to energy efficiency 

achieved in other states. PacifiCorp suggests that NWEC and others are a) ignoring the 

contributions of load management investments, b) not considering market 

transformation savings, and c) failing to recognize differences in factors such as 

average energy use per customer, age of homes, etc. 

PacifiCorp replied to Sierra Club’s comments by pointing out that there are many factors 

that contribute to declining DSM potentials over time and that Energy Trust’s potential 

assessments also show declining DSM over time. PacifiCorp explains that new 

potential assessments will be conducted every two years, so parties should not be 

overly concerned with declining numbers beyond the action plan period.

PacifiCorp indicates the contract for the next conservation potential study was finalized 

in June 2013 so it is not feasible to incorporate input from Staff on the scope of the 

study. PacifiCorp indicated they will schedule a date to review the scope of the study 

with Staff. The Company indicates the conservation potential study will be used to 

develop an implementation plan to deliver the Class 2 DSM resources selected in the 

2015 IRP, recognizing that implementation plans in each state must be approved by 

that state. 

PacifiCorp agreed to provide twice yearly updates on the status of DSM IRP acquisition 

goals in 2014 and 2015.

Staff Recommendation

Staff is not persuaded by PacifiCorp’s arguments that it is achieving the same amount 

or more conservation in its other states as it is in Oregon through Energy Trust. 

Nonetheless, Staff recommends the Commission acknowledge proposed action item 7a 

related to DSM with Staff’s four additions described below. 

Recommended additions to Action Item 7a

1) Provide twice yearly updates on the status of DSM IRP acquisition goals to the 

Oregon Commission in 2014 and 2015 at regular public meetings. Summarize 

where efforts have deviated from previously agreed upon action items and report 

on progress toward specific DSM targets for all states other than Oregon. As 

part of these updates, provide information on progress in exploring energy 

efficiency opportunities with special contract customers in next round of contract 

negotiations.

2) Include in the 2014 conservation potential study an Implementation Plan specific 

to PacifiCorp service territory for all states other than Oregon which quantifies 
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how much Class 2 DSM programs can be accelerated and how much it will cost 

to accelerate acquisition.

3) In the 2015 IRP and in quarterly updates, report back on the status of negotiating 

energy efficiency projects with special contract customers.

4) Going forward, in future IRPs, the Company will provide yearly Class 1 and Class 

2 DSM acquisition targets in both GWh and MW for each year in the planning 

period, by state.

5.2 Class 1 DSM 

Background

The Company does not have any action items related to Class 1 DSM. PacifiCorp 

defines Class 1 DSM as programs for which capacity savings occur as a result of active 

Company control or advanced scheduling. Examples include dispatchable demand 

response and dispatchable irrigation programs. The preferred portfolio in this IRP does 

not include any Class 1 DSM until 2027, by which time 400+ MW of a new gas plant has 

been added along with 650 MW of new wind. 

In its initial comments, NWEC points out that in the 2013 IRP Volume 1 states that the 

Company completed an analysis of the feasibility and costs of west-side Class 1 

irrigation control but that “it was not selected as an economic resource in the first ten 

years of the 2013 IRP preferred portfolio.”34 NWEC suggests that lack of information in 

the 2013 IRP and its appendices make it difficult to understand what assumptions led to 

this surprising result and suggests that closer Commission scrutiny of this decision is 

warranted give the expected value of summer peak load reduction to the company’s 

system give the estimated summer peak resource deficit of 824 MW beginning in 2013 

and reaching 2308 MW by 2022. NWEC goes on to recommend close Commission 

scrutiny of the underlying model assumptions in the 2013 IRP that seem to have led to 

what they call an undervaluing of Class 1 DSM. Additionally, NWEC thinks the capacity 

oriented selections in case EG2-C15, and the potential contribution to this case’s least 

risk/least cost ranking should be analyzed more fully in the IRP.

NWEC notes that load control and demand response resources, similar to Class 2 DSM 

resources, need to be building incrementally over time. NWEC asserts that PacifiCorp’s 

2013 IRP analysis and strategies undervalue these resources. NWEC does not object 

to any specific 2013 Action Item related to load control or demand response, however, 

they recommend that the Company consider whether demand side resources should be 

 

34 IRP, Volume 1, page 257
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assessed in a manner that more clearly reflects the incremental nature of these 

resources, as well as the lost opportunity when loads increase, in the 2015 IRP.

ODOE supports NWEC’s request from its Initial Comments that “the Commission 

encourage the Company to increase the amount and sophistication of its overall 

analysis regarding demand response and other load control tools in the next IRP.”35 

ODOE agrees with NWEC that utilization of load control capabilities should be 

evaluated for their potential to reduce customer energy costs over the long-term. 

ODOE suggests that PacifiCorp’s 2013 Action Plan should include a Class 1 DSM pilot 

in Oregon and the Commission should direct PacifiCorp to conduct a more detailed 

analysis of demand response opportunities in future IRPs consistent with IRP Guideline 

7 of Order No. 07-002, which states, “Plans should evaluate demand response 

resources, including voluntary rate programs, on par with other options for meeting 

energy, capacity, and transmission needs...” ODOE notes how PacifiCorp’s 2011 IRP 

included a commitment to acquire at least 140 MW of Class 1 DSM resources by 2013 

and a commitment to implement a commercial curtailment project that includes 

customer-owned standby generation opportunities, if cost effective, by 2012. However, 

the preferred portfolio in the 2013 IRP does not contain any Class 1 DSM until 2027 and 

PacifiCorp cancelled the commercial curtailment project due to a revised load forecast 

that the Company said suggests the direct load control if not cost-effective.

ODOE suggests that even if not all Class 1 DSM options are cost-effective in the shortterm, ODOE supports a staged approach to advance PacifiCorp’s technical capabilities 

to use demand response technologies. ODOE suggests PacifiCorp can then best 

discern the most cost-effective approaches and report on those findings in the next IRP. 

ODOE recommends that PacifiCorp pursue a Class 1 DSM pilot in Oregon and at least 

one other state before filing its next IRP. Although ODOE doesn’t have a specific 

recommendation on a capacity target for the pilot at this time, ODOE suggests that 

PacifiCorp’s current proposal to have zero Class 1 DSM resources for over a decade, 

with no plan to evaluate these resources further, is insufficient. 

PacifiCorp Response

PacifiCorp, in its Reply Comments, disagrees with NWEC’s rational in asserting the 

absence of Class 1 DSM resources in the preferred portfolio indicates that Class 1 DSM 

programs are undervalued in the 2013 IRP. The Company claims that with reduced 

loads, the need for new resources is greatly reduced as compared to the 2011 IRP and

load control and demand response are not needed. 

 

35 NW Energy Coalition LC 57 Initial Comments at 7-8.
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PacifiCorp laments that ODOE does not identify how it views PacifiCorp’s current 

consideration of Class 1 DSM resources to be deficient. The Company points out that a 

range of different Class 1 DSM products are developed in resource potential studies 

and used as inputs for portfolio modeling. PacifiCorp does not support ODOE’s 

recommendation to implement a Class 1 DSM pilot in Oregon.

Staff Recommendation

Staff appreciates NWEC’s and ODOE’s comments and the Company’s response related 

to Class 1 DSM. Staff recommends that during the public involvement process for the 

next IRP, the Company clarify its assumptions associated with Class 1 DSM and how it 

is being valued in PacifiCorp’s production cost model. Staff does not agree with ODOE 

that a Class 1 DSM pilot should be required by the Company before it’s next IRP filing. 

Staff would be amenable to the Company proposing a pilot, but does not think this is 

something that should be required by the Commission at this time. 

6. RENEWABLES

PacifiCorp proposes five action items related to renewable energy plus two action items 

specifically related to distributed generation as shown in Attachment A. Action Item 1a, 

1e, 2a and 2b are business as usual type activities that do not require commission 

acknowledgment. 

6.1 Renewable Portfolio Standard (RPS) Compliance – Action Item 1b

Action Item 1b is related to RPS compliance and asks for acknowledgement to use 

unbundled renewable energy credits (RECs) to meet Renewable Portfolio Standard 

(RPS) compliance through an annual request for proposal (RFP) process. The 

Company proposes that it is cheaper to meet RPS standards with RECs than to build 

new renewable resources.

In Staff’s final comments, we recognized the Company’s efforts to meet RPS 

requirements in the lowest cost manner using RECs, where possible. However, 

PacifiCorp didn’t project costs associated with those RECs which Staff saw as a gap in 

the analysis. Thus, Staff recommended that Action Item 1b be acknowledged with the 

conditions that REC prices be explicitly incorporated into portfolio analysis in the future 

and a forecasted range of REC prices be included in the IRP update and the 2015 IRP. 

Company Response

The Company did not agree with Staff’s proposed additions to Action Item 1b. The 

Company expressed concerns that publishing a REC price projection in the IRP could 
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influence prices when the Company sells or purchases RECs in the market, which 

would harm customers. The Company instead proposes to continue to monitor REC 

prices and consider the upper limits of future REC prices in the context of state-specific 

RPS rules when evaluating compliance alternatives for a given state RPS program.

Staff’s Recommendation

Staff understands the difficulty and potential risks of developing and publishing forward 

market price curves for RECs. For that reason, Staff recommends acknowledging

action item 1b as proposed. 

6.2 REC Optimization – Action Item 1c

Action Item 1c is to issue reverse RFPs on a quarterly basis to sell RECs not required to 

meet state RPS compliance obligations. In our final comments, Staff recommended the 

Commission not acknowledge this action item because we believe the Company’s 

renewable resources should be made available to Oregon, with the associated 

compensation based on market value of the RECs. PacifiCorp has bundled RECs from 

other PacifiCorp states (Utah and Idaho) that could be transferred to Oregon to meet 

RPS rather than being sold on the market. Staff would like PacifiCorp to consider a 

strategy where these RECs would be acquired by Oregon rather than sold to the higest 

bidder. The other states would be compensated. 

Oregon Staff is currently working through the Multi-State Process (MSP) to acquire 

bundled RECs from other PacifiCorp jurisdictions. Because Action Item 1c conflicts with 

this objective, Staff does not recommend acknowledgment of this Action Plan item. 

Company Response

PacifiCorp states that Staff’s recommendation on this item is an alternative cost 

allocation method better suited for the MSP. PacifiCorp believes it is not appropriate 

for IRP Action Items to be shelved because Oregon has been discussing acquiring 

RECs from other jurisdictions through the MSP process. PacifiCorp states that until a 

specific agreement among states is in place, that will accommodate the transfer of 

RECs from one jurisdiction to Oregon, PacifiCorp will continue to implement Action Item 

9c.

Staff Recommendation

Staff will continue to pursue this issue through the MSP. In the meantime, how the 

Company sells RECs currently allocated to other states, is not technically an issue that 

requires Commission acknowledgement in an IRP. Therefore, instead of 

recommending the Commission not acknowledge this action item, Staff suggests that 
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this is another “business as usual” action item that does not require Commission 

acknowledgement. 

6.2 Solar – Action Item 1d

The Company is seeking acknowledgement of Action Item 1d to issue an RFP to obtain 

Oregon solar photovoltaic resources to meet the Oregon small solar compliance 

obligation of Oregon House Bill 3039. Staff has reviewed the economics of this project 

and believes it is a good deal for ratepayers. Energy Trust incentive dollars are also 

being provided to the project. Staff recommends the Commission acknowledge this 

action item.

6.4 Other renewables action items

Staff contends that Action Items 1a, 1e, 2a and 2b do not require Commission 

acknowledgement. 

6.5 Renewables Capacity Contribution - Action Item 1e

Action Item 1e is to track and report the statistics used to calculate capacity contribution 

from wind resources and available solar information as a means of testing the validity of 

the peak load carrying capability (PLCC) method.

Staff Position

In Staff’s final comments, we indicated that we support PacifiCorp tracking and reporting 

statistics used to test the validity of the PLCC of solar and wind. Staff notes that the 

data collected will allow the Company to compare the capacity contribution calculated 

through the PLCC analysis with similar “effective load carrying capability” (ELCC) 

methods to fully assess solar and wind capacity contributions to the system reliability. 

RNP Position

RNP says that subsequent proceedings (IRPs, IRP updates and investigative dockets) 

should include updated capacity factors and capacity values for renewable resources. 

RNP argued in their initial comments that inaccurate capacity value assumptions 

contributed to the decreased selection of renewable resources. RNP contends that the 

capacity value methodology used by the Company excluded the majority of reliability 

benefits provided by renewable resources. Instead, RNP proposes that the 

Commission direct the Company to use the ELCC methodology, consistent with best 

national practices. RNP strongly supports Staff’s recommendation to compare the 

capacity contributions using PLCC and what RNP calls the more accurate metric of 

ELCC. 
Staff Report LC 57

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Company Response

PacifiCorp agreed to consider Staff’s recommendations to compare the capacity 

contributions of wind and solar resources between alternative methods.

Staff Recommendation

Staff recommends RNP and other interested stakeholders participate with Staff and the 

Company in the pre-IRP meetings for the 2015 IRP and follow up on these metrics 

through that process. 

6.6 Cost of PV used in modeling

NWEC Position

NWEC and other interveners expressed concerns about the costs of solar PV used in 

this IRP. In its initial comments, NWEC provided detail on recent developments on 

current costs and future projections, highlighting the robust downward cost trends and 

analysis suggesting those trends will continue. In its initial comments, NWEC pointed 

out that PAC’s estimates for solar PV costs start too high and do not incorporate the 

likely decline in costs over both the short and long term. NWEC makes the case using 

data from multiple sources.. The result of these too high estimates, NWEC asserts, is 

thataside from the small amount of distributed generation enabled under state policies, 

there are no further acquisition targets or pilot programs included in PacifiCorp’s 2013 

Action Plan, despite PacifiCorp’s territory including what NWEC calls “some of the best 

resources in the nation.”36

NWEC is not swayed by the Company’s response that PacifiCorp’s consultant Cadmus, 

based PV costs on the best information available. NWEC asserts that Cadmus’ 

analysis relied on older studies for current costs and did not properly incorporate an 

experience curve assessment for future costs and therefore, the assumptions used in 

the IRP modeling basically assumed flat costs for the next decade. NWEC mentions

that PacifiCorp noted a recent leveling and uptick in solar modules pricing during 2013. 

NWEC provides industry data that supports the position that this uptick is likely 

temporary in duration. 

NWEC supports the Company’s proposal to reassess solar resource cost assumptions 

on an ongoing basis and review the most recent market data available during the

preparation of the 2015 IRP.

Company Response

The Company did not respond to these assertions in their Opening or final comments.

 

36 LC 57 NWEC Initial Comments page 9.
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Staff Recommendation

Staff appreciates NWEC’s research and comments on this issue of solar PV prices and 

solar resources being used by PacifiCorp in IRP modeling. Staff recommends NWEC 

continue to participate in IRP development meetings and submit input in writing on PV 

prices. 

6.7 Trigger point analysis for renewables

RNP proposes that PacifiCorp perform a trigger point analysis for new renewable 

resources in its next IRP. The trigger point analysis would identify the levelized cost of 

energy for wind and solar resources required to promote their selection in System 

Optimizer. 

Company Response

PacifiCorp states that is appreciates RNP’s comments and will consider its 

recommendation as the Company works with stakeholders to develop scenarios and 

sensitivities in the 2015 IRP and looks forward to working with RNP in defining potential 

parameters for a trigger point analysis during the 2015 IRP public input process. 

Staff Recommendation

Staff supports PacifiCorp working with RNP during the 2015 IRP public input process to 

develop the type of information RNP is looking for in a trigger point analysis for 

renewable resources. Staff recommends RNP develop specific suggestions in writing 

as part of that process. 

7. LOAD FORECAST

7.1 Net Metering

Staff expressed concerns that the Company’s modeling may not be adequately 

accounting for potential future load reductions due to net metering. Staff disagrees that 

PacifiCorp’s forecast methodology accurately anticipates net metering growth. 

Company Response

The Company continues to believe its forecast methodology accurately anticipates net 

metering growth, but says it looks forward to working through the issue with Staff in the 

2015 IRP. 

Staff Recommendation
Staff Report LC 57

March 4, 2014

Page 45

Staff will engage with the Company on this issue in the 2015 IRP Public Input Process.

7.2 Direct Access Loads

Staff and ICNU agree that PacifiCorp’s load forecasts could be inappropriately high due 

to the Company not taking into account customers that may sign-up for long-term direct 

access. Staff asserts that the Company’s assumption of zero long-term direct access 

load is not reasonable.

ICNU agrees with Staff that PacifiCorp should adjust its expected loads based on 

customers permanently electing direct access. ICNU elaborates on this by explaining 

that in Docket No. UE 267, the Commission is considering a five-year opt-out program 

in which direct access customers can opt out from cost of service rates on a permanent 

or long-term basis. 

Company Response

PacifiCorp responds that at this time the Company is unable to forecast which 

customers will choose the direct access five-year opt-out program due to the specifics 

of each customer’s load profile, economic circumstances, risk tolerance, or pricing they 

may have received from a qualified electricity service supplier. PacifiCorp indicates that 

it will evaluate whether any of its planning assumptions will need to be modified after the 

final order is issued in Docket UE 267.

Staff Recommendation

The Company states that “the Company is unable to forecast which customers will 

choose the direct access five-year opt-out program”. However, the Company has 

forecasted the direct access participation. Specifically, it forecasts zero participation. 

This position by the company is the equivalent of stating “The Company is unable to 

accurately forecast the level of load growth, therefore the company will assume that no 

load growth occurs.” Like most pieces of the IRP, planning for future direct access 

participation involves hypothesis and speculation. PacifiCorp needs to ensure its load 

forecast for the 2015 IRP takes into account the outcome of UE 267 and make relevant 

assumptions clear in the 2015 IRP planning process and final IRP.

8. MODELING AND PROCESS SUGGESTIONS

In our final comments, Staff makes the case that PacifiCorp’s modeling could use 

improvements in the areas of (1) the diversity of portfolios created through System 

Optimizer; (2) the natural gas input to the PaR model biases the analysis in favor of 

coal; (3) PaR is not varying coal prices, CO2 prices, or other environmental compliance 
Staff Report LC 57

March 4, 2014

Page 46

costs stochastically, unlike other key variables, which mutes risk and biases the model 

towards coal heavy portfolios, and (4) stochastic treatment of system loads are favoring 

overbuilt scenarios. 

Staff and the Company disagree on how the risk metric that comes out of the 

Company’s stochastic modeling in the IRP should be applied and expressed. Staff 

continues to contend that the risk metric should be the upper tail mean present value 

revenue requirement (PVRR) alone rather than the upper tail mean PVRR minus the 

mean PVRR. Staff made this same case back in PacifiCorp’s IRP Docket LC 42, 

wherein Order 08-232, the Commission said “We direct the Company to rank portfolios 

according to these metrics (95th percentile and Upper-Tail [mean] PVRR) in the next 

IRP....” 

NWEC makes the case that the current IRP modeling framework does not capture the 

full diversity of risk hedging value of clean energy resources such as energy efficiency, 

demand response and renewables. NWEC points out the diversity of opinions about 

what will happen with natural gas prices and as a result some utilities are beginning to 

invest in wind and other clean energy resources above any regulatory requirements in 

order to hedge against gas price volatility. In NWEC’s view, relying less heavily on gas 

going forward is the prudent path, both because of continued volatility and the risk in 

long-term price trends. NWEC recommends the Commission urge the Company to 

review and improve its methodology for including natural gas prices uncertainty and risk 

in IRP modeling in the next IRP.

Due to the increasing complexity of PacifiCorp’s system, ODOE recommends the 

Commission order PacifiCorp to conduct a stochastic capacity credit study using 8,760 

hours of data per year to better account for the capacity contribution of variable 

resources, such as wind. 

Company Response

The Company points out that consistent with action item 11a, it held a modeling process 

improvement workshop in September 2013. PacifiCorp indicates it is currently 

considering comments it received from parties, including Staff, following the workshop. 

It is looking at ways to achieve a wider range of portfolio diversity and ways to 

accommodate more risk analysis using the PaR model. PacifiCorp also indicates it 

plans to update its stochastic parameters for the 2015 IRP and plans to have a 

workshop to discuss stochastic modeling with stakeholders as part of the 2015 IRP 

public process and it is evaluating methods to develop capacity contribution 

assumptions for renewable resources. 
Staff Report LC 57

March 4, 2014

Page 47

Relative to the risk metric issue, the Company emphasized that the use of the Staffproposed alternative approach would not have altered “the outcome of the initial 

screening process for the 2013 IRP....” The Company recommends addressing Staff’s 

concerns by including a discussion of the risk metric as an agenda item in the 2015 IRP 

public process, allowing stakeholders to discuss alternatives when evaluating risk in the 

initial screening process. 

PacifiCorp does not support ODOE’s recommendation that the Commission require the 

Company to conduct a stochastic capacity credit study using 8,760 hours of data per 

year and is considering methods developed to approximate reliability-based methods 

such as the ELCC, which are computationally intensive, with methods that require less 

data. The Company suggests ODOE’s recommendation may be overly prescriptive and 

would prevent the Company from exploring alternatives that achieve the intended result 

in a way that requires significantly less data and computational horsepower. 

Staff Recommendation

Staff appreciates the Company’s willingness to work with parties on the improvements 

suggested by Staff and others related to modeling and process. 

Staff is not convinced by PacifiCorp’s assertion that changing the risk metric would not 

have altered the outcome of the initial screening process for the 2013 IRP. In other 

words, what may have been an illogical process did not in the current case cause the 

Company to make a bad decision – not to say that under other circumstances the 

illogical process may in fact had done so. Staff is supportive of PacifiCorp’s 

recommendation that this issue be discussed in the 2015 IRP stakeholder involvement 

process. 

Staff encourages ODOE to work with the Company and stakeholders in the 2015 IRP 

public involvement process on feasible alternatives for assessing stochastic capacity 

credits.

9. ENERGY STORAGE

ODOE recommends that PacifiCorp’s IRP Action Plan should include an energy storage 

pilot and the Commission should direct PacifiCorp to provide a more comprehensive 

treatment of energy storage in future IRPs. ODOE indicates that in PacifiCorp’s 2011 

IRP action plan, PacifiCorp committed to an energy storage demonstration project in 
Staff Report LC 57

March 4, 2014

Page 48

Utah, that was later cancelled.37 This IRP does not recommend further action on 

energy storage.

ODOE acknowledges that PacifiCorp commissioned a study in 2011 with HDR 

Engineering to develop a current catalog of commercially available and emerging 

energy storage technologies and those results of the report were incorporated into the 

System Optimizer model. 

ODOE suggests that future IRPs should offer a more comprehensive treatment of 

energy storage.

Company Response

In response, PacifiCorp indicates it does not support ODOE’s recommendation to 

implement an energy storage pilot in Oregon. PacifiCorp indicates its model allows for 

energy storage to be selected and that results from the 2013 IRP do not currently 

support implementing an energy storage pilot in Oregon. PacifiCorp says it will continue 

to update cost and performance assumptions and assess energy storage resources in 

future IRPs.

Staff Recommendation

In the final Commission Order in LC 52, the Company’s 2011 IRP, the Commission 

specifically stated:

Moreover, we support PacifiCorp's plan to proceed with development and 

implementation of an energy storage demonstration project in the state of Utah. 

We strongly encourage PacifiCorp to evaluate energy storage options capable of 

addressing the summer peak in Utah as a means of delaying the need for a new 

thermal resource on the company's eastern system. 

Staff supports PacifiCorp continuing to update cost and performance assumptions and 

asses energy storage resources in future IRPs. Staff encourages ODOE to participate 

in stakeholder meetings for the 2015 IRP and offer specific suggestions for treatment of 

energy storage as applicable.

 

37 In the 2013 IRP Volume I, page 254 PacifiCorp indicates that the energy storage 

demonstration project progressed to the point of testing a five kilowatt-hour electrostatic 

generator. A report on the project was sent to the public in May 2012. Due to lack of supplier 

funding, PacifiCorp indicates that in 2013 the project is no longer being pursued by the 

Company.
Staff Report LC 57

March 4, 2014

Page 49

PROPOSED COMMISSION MOTION:

PacifiCorp’s 2013 Integrated Resource Plan be acknowledged with the revised action 

items recommended by Staff as contained in Attachment C to this report.
Attachment A

LC 57 Originally Proposed Action Items:

1. Renewable Resource Actions

Action Item 1a. - Wind Integration

Update the wind integration study for the 2015 IRP. The updated wind integration study 

will consider the implications of an energy imbalance market along with comments and 

feedback from the technical review committee and IRP stakeholders provided during the 

2012 Wind Integration Study.

Action Item 1b. - Renewable Portfolio Standard Compliance

With renewable portfolio standard (RPS) compliance achieved with unbundled 

renewable energy credit (REC) purchases, the preferred portfolio does not include 

incremental renewable resources prior to 2024. Given that the REC market lacks 

liquidity and depth beyond one year forward, the Company will pursue unbundled REC 

requests for proposal (RFP) to meet its state RPS compliance requirements.

– Issue at least annually, RFPs seeking then current-year or forward-year vintage 

unbundled RECs that will qualify in meeting Washington renewable portfolio 

standard obligations.

– Issue at least annually, RFPs seeking historical, then current-year, or forwardyear vintage unbundled RECs that will qualify for Oregon renewable portfolio 

standard obligations. As part of the solicitation and bid evaluation process, 

evaluate the tradeoffs between acquiring bankable RECs early as a means to 

mitigate potentially higher cost long-term compliance alternatives.

– Issue at least annually, RFPs seeking then current-year or forward-year vintage 

unbundled RECs that will qualify for California renewable portfolio standard 

obligations.

Action Item 1c. - Renewable Energy Credit Optimization

On a quarterly basis, issue reverse RFPs to sell RECs not required to meet state RPS 

compliance obligations.

Action Item 1d. - Solar

– Issue an RFP in the second quarter of 2013 soliciting Oregon solar photovoltaic 

resources to meet the Oregon small solar compliance obligation (Oregon House 

Bill 3039). Coordinate the selection process with the Energy Trust of Oregon to 

seek 2014 project funding. Complete evaluation of proposals and select potential 

winning bids in the fourth quarter of 2013.

– Issue a request for information 180 days after filing the 2013 IRP to solicit 

updated market information on utility scale solar cost

Action Item 1e. - Capacity Contribution

Track and report the statistics used to calculate capacity contribution from wind 

resources and available solar information as a means of testing the validity of the peak 

load carrying capability (PLCC) method.
LC 57 Attachment A – Originally Proposed Action Items

March 4, 2014

Page 2

2

2. Distributed Generation Actions

Action Item 2a. - Distributed Solar

Manage the expanded Utah Solar Incentive Program to encourage the installation of the 

entire approved capacity. Beginning in June 2014, as stipulated in the Order in Docket 

No. 11-035-104, the Company will file an Annual Report with program results, system 

costs, and production data. These reports will also provide an opportunity to evaluate 

and improve the program as the Company will use this opportunity to recommend 

changes. Interested parties will have an opportunity to comment on the report and any 

associated recommendations.

Action Item 2b. - Combined Heat & Power (CHP)

Pursue opportunities for acquiring CHP resources, primarily through the Public Utilities 

Regulatory Policies Act PURPA Qualifying Facility contracting process. For the 2013 

IRP Update, complete a market analysis of CHP opportunities that will: (1) assess the 

existing, proposed, and potential generation sites on PacifiCorp’s system; (2) assess 

availability of fuel based on market information; (3) review renewable resource site 

information (i.e. permits, water availability, and incentives) using available public 

information; and (4) analyze indicative project economics based on avoided cost pricing 

to assist in ranking probability of development.

3. Firm Market Purchase Actions

Action Item 3a. - Front Office Transactions

Acquire economic front office transactions or power purchase agreements as needed

through the summer of 2017.

– Resources will be procured through multiple means, such as periodic market RFPs 

that seek resources less than five years in term, and bilateral negotiations.

– Include in the 2013 IRP Update a summary of the progress the Company has made to 

acquire front office transactions over the 2014 to 2017 forward period.

4. Flexible Resource Actions

Action Item 4a. - Energy Imbalance Market (EIM)

Continue to pursue the EIM activities with the California Independent System Operator 

and the Northwest Power Pool to further optimize existing resources resulting in 

reduced costs for customers.

5. Hedging Actions

Action Item 5a. - Natural Gas Request for Proposal

Convene a workshop for stakeholders by October 2013 to discuss potential changes to

the Company’s process in evaluating bids for future natural gas RFPs, if any, to secure 

additional long-term natural gas hedging products.
LC 57 Attachment A – Originally Proposed Action Items

March 4, 2014

Page 3

3

6. Plant Efficiency Improvement Actions

Action Item 6a. - Plant Efficiency Improvements

Production efficiency studies have been conducted to satisfy requirements of the 

Washington I-937 Production Efficiency Measure that have identified categories of cost 

effective production efficiency opportunity.

– By the end of the first quarter of 2014, complete an assessment of the plant 

efficiency opportunities identified in the Washington I-937 studies that might be 

applicable to other wholly owned generation facilities.

– Prior to initiating modeling efforts for the 2015 IRP, determine a multi-state 

“total resource cost test” evaluation methodology to address regulatory recovery 

among states with identified capital expenditures.

– Prior to initiating modeling efforts for the 2015 IRP, present to IRP stakeholders 

in a public input meeting the Company’s recommended approach to analyzing 

cost effective production efficiency resources in the 2015 IRP.

7. Demand Side Management (DSM) Actions

Action Item 7a. - Class 2 DSM

Acquire 1,425 – 1,876 GWh of cost-effective Class 2 energy efficiency resources by the 

end of 2015 and 2,034 – 3,180 GWh by the end of 2017.

 Collaborate with the Energy Trust of Oregon on a pilot residential home 

comparison report program to be offered to Pacific Power customers in 2013 and 

2014. At the conclusion of the pilot program and the associated impact 

evaluation, assess further expansion of the program.

 Implement an enhanced consolidated business program to increase DSM 

acquisition from business customers in all states excluding Oregon.

o Utah base case schedule is 1st quarter 2014 with an accelerated target of 3rd

quarter 2013.

o Washington base case schedule is 4th quarter 2014, with an accelerated 

target of 1st quarter 2014.

o Wyoming, California, and Idaho base case schedule is 4th quarter 2014, with 

an accelerated target of 2nd quarter 2014.

 Accelerate to the 2nd quarter of 2014, an evaluation of waste heat to power 

where generation is used to offset customer requirements – investigate how to 

integrate opportunities into the DSM portfolio.

 Increase acquisitions from business customers through prescriptive measures by

expanding the “Trade Ally Network”.

o Base case target in all states is 3rd quarter 2014, with an accelerated target 

of 4th quarter 2013

 Accelerate small-mid market business DSM acquisitions by contracting with third 

party administrators to facilitate greater acquisitions by increasing marketing, 

outreach, and management of comprehensive custom projects by 1st quarter 

2014.

 Increase the reach and effectiveness of “express” or “typical” measure offerings 

by increasing qualifying measures, reviewing and realigning incentives, 
LC 57 Attachment A – Originally Proposed Action Items

March 4, 2014

Page 4

4

implementing a direct install feature for small commercial customers, and 

expanding the residential refrigerator and freezer recycling program to include 

commercial units.

o Utah base case schedule is 1st quarter 2014 with an accelerated target of 3rd

quarter 2013.

o Washington base case schedule is 4th quarter 2014, with an accelerated 

target of 1st quarter 2014.

o Wyoming, California, and Idaho base case schedule is 4th quarter 2014, with 

an accelerated target of 2nd quarter 2014.

 Increase the reach of behavioral DSM programs:

o Evaluate and expand the residential behavioral pilot.

o Utah base case schedule is 2nd quarter 2014, with an accelerated 

target of 4th quarter 2013.

o Accelerate commercial behavioral pilot to the end of the first quarter 2014.

o Expand residential programs system-wide pending evaluation results.

o System-wide target is 3rd quarter 2015, with an accelerated target of 

3rd quarter 2014.

 Increase acquisition of residential DSM resources:

o Implement cost effective direct install options by the end of 2013.

o Expand offering of “bundled” measure incentives by the end of 2013.

o Increase qualifying measures by the end of 2013.

o Review and realign incentives.

o Utah schedule is 1st quarter 2014

o Washington base case schedule is 2nd quarter 2014, with accelerated 

target of 1st quarter 2014.

o Wyoming, California, and Idaho base case schedule is 3rd quarter 

2014, with an accelerated target of 2nd quarter 2014

o Accelerate acquisitions by expanding refrigerator and freezer recycling to 

incorporate retail appliance distributors and commercial units – 3rd quarter 

2013.

o By the end of 2013, complete review of the impact of accelerated DSM on 

Oregon and the Energy Trust of Oregon, and re-contract in 2014 for 

appropriate funding as required.

o Include in the 2013 IRP Update Class 2 DSM decrement values based upon 

accelerated acquisition of DSM resources.

o Include in the 2014 conservation potential study an analysis testing 

assumptions in support of accelerating acquisition of cost-effective Class 2 

DSM resources, and apply findings from this analysis into the development of 

candidate portfolios in the 2015 IRP.

Action Item 7b. - Class 3 DSM

Develop a pilot program in Oregon for a Class 3 irrigation time-of-use program as an 

alternative approach to a Class 1 irrigation load control program for managing irrigation 

loads in the west. The pilot program will be developed for the 2014 irrigation season and 

findings will be reported in the 2015 IRP.
LC 57 Attachment A – Originally Proposed Action Items

March 4, 2014

Page 5

5

8. Coal Resource Actions

Action Item 8a. - Naughton Unit 3

– Continue permitting and development efforts in support of the Naughton Unit 3 

natural gas conversion project. The permit application requesting operation on 

coal through year-end 2017 is currently under review by the Wyoming 

Department of Environmental Quality, Air Quality Division. 

– Issue a request for proposal to procure gas transportation for the Naughton plant 

as required to support compliance with the conversion date that will be 

established during the permitting process.

– Issue an RFP for engineering, procurement, and construction of the Naughton 

Unit 3 natural gas retrofit as required to support compliance with the conversion 

date that will be established during the permitting process.

Action Item 8b. - Hunter Unit 1

Complete installation of the baghouse conversion and low NOX burner compliance 

projects at Hunter Unit 1 as required by the end of 2014.

Action Item 8c. - Jim Bridger Units 3 and 4

Complete installation of selective catalytic reduction (SCR) compliance projects at Jim 

Bridger Unit 3 and Jim Bridger Unit 4 as required by the end of 2015 and 2016, 

respectively.

Action Item 8d. - Cholla Unit 4

Continue to evaluate alternative compliance strategies that will meet Regional Haze 

compliance obligations, related to the U.S. Environmental Protection Agency’s Federal 

Implementation Plan requirements to install SCR equipment at Cholla Unit 4. Provide an

update of the Cholla Unit 4 analysis regarding compliance alternatives in the 2013 IRP 

Update.

9. Transmission Actions

Action Item 9a. - System Operational and Reliability Benefits Tool (SBT)

60 days after filing the 2013 IRP, establish a stakeholder group and schedule 

workshops to further review the System

Benefit Tool (SBT).

– For the 2013 IRP Update, complete additional analysis of the Energy Gateway 

West Segment D that evaluates staging implementation of Segment D by subsegment.

– In preparation for the 2015 IRP, continue to refine the SBT for Energy Gateway 

West Segment D and develop SBT analyses for additional Energy Gateway 

segments.

Action Item 9b. - Energy Gateway Permitting
LC 57 Attachment A – Originally Proposed Action Items

March 4, 2014

Page 6

6

Continue permitting for the Energy Gateway transmission plan, with near term targets 

as follows:

– Segment D, E, and F, continue funding of the required federal agency 

permitting environmental consultant as actions to achieve final federal permits.

– Segment D, E, and F, continue to support the federal permitting process by 

providing information and participating in public outreach projected through the 

next 2 to 4 years.

– Segment H Cascade Crossing, complete benefits analysis in 2013.

– Segment H Boardman to Hemingway, continue to support the project under the 

conditions of the Boardman to Hemingway Transmission. Project Joint Permit 

Funding Agreement, projected through 2015.

Action Item 9c. - Sigurd to Red Butte 345 kilovolt Transmission Line

Complete project construction per plan.

10.Planning Reserve Margin Actions

Action Item 10a. - Planning Reserve Margin

Continue to evaluate in the 2015 IRP the results of a System Optimizer portfolio 

sensitivity analysis comparing a range of planning reserve margins considering both 

cost and reliability impacts of different levels of planning reserve margin assumptions. 

Complete for the 2015 IRP an updated planning reserve margin analysis that is shared 

with stakeholders during the public process.

11.Planning and Modeling Process Improvement Actions

Action Item 11a. - Modeling and Process

Within 90 days of filing the 2013 IRP, schedule an IRP workshop with stakeholders to 

discuss potential process improvements that can more efficiently achieve meaningful 

cost and risk analysis of resource plans in the context of the IRP and implement

process improvements in the 2015 IRP.

Action Item 11b. - Cost/Benefit Analysis of DSM Resource Alternatives

Complete a cost/benefit analysis on the level of detail used to evaluate prospective 

DSM resources in the IRP. The analysis will consider the tradeoffs between model runtime and resulting resource selections, will be shared with stakeholders early in the 

2015 IRP public process, and will inform how prospective DSM resources will be 

aggregated in developing resource portfolios for the 2015 IRP.
Attachment B

Staff’s Recommended Redline Changes to Proposed Action Items:

1. Renewable Resource Actions

DOES NOT REQUIRE ACKNOWLEDGEMENT Action Item 1a. - Wind Integration

Update the wind integration study for the 2015 IRP. The updated wind integration study 

will consider the implications of an energy imbalance market along with comments and 

feedback from the technical review committee and IRP stakeholders provided during the 

2012 Wind Integration Study.

ACKNOWLEDGE AS PROPOSED

Action Item 1b. - Renewable Portfolio Standard Compliance

With renewable portfolio standard (RPS) compliance achieved with unbundled 

renewable energy credit (REC) purchases, the preferred portfolio does not include 

incremental renewable resources prior to 2024. Given that the REC market lacks 

liquidity and depth beyond one year forward, the Company will pursue unbundled REC 

requests for proposal (RFP) to meet its state RPS compliance requirements.

– Issue at least annually, RFPs seeking then current-year or forward-year vintage 

unbundled RECs that will qualify in meeting Washington renewable portfolio 

standard obligations.

– Issue at least annually, RFPs seeking historical, then current-year, or forwardyear vintage unbundled RECs that will qualify for Oregon renewable portfolio 

standard obligations. As part of the solicitation and bid evaluation process, 

evaluate the tradeoffs between acquiring bankable RECs early as a means to 

mitigate potentially higher cost long-term compliance alternatives.

– Issue at least annually, RFPs seeking then current-year or forward-year vintage 

unbundled RECs that will qualify for California renewable portfolio standard 

obligations.

DOES NOT REQUIRE ACKNOWLEDGEMENT 

Action Item 1c. - Renewable Energy Credit Optimization

On a quarterly basis, issue reverse RFPs to sell RECs not required to meet state RPS 

compliance obligations.

ACKNOWLEDGE AS PROPOSED

Action Item 1d. - Solar

– Issue an RFP in the second quarter of 2013 soliciting Oregon solar photovoltaic 

resources to meet the Oregon small solar compliance obligation (Oregon House 

Bill 3039). Coordinate the selection process with the Energy Trust of Oregon to 

seek 2014 project funding. Complete evaluation of proposals and select potential 

winning bids in the fourth quarter of 2013.

– Issue a request for information 180 days after filing the 2013 IRP to solicit 

updated market information on utility scale solar cost.
LC 57 Attachment B – Staff’s proposed redline changes to action items

March 4, 2014

Page 2

2

DOES NOT REQUIRE ACKNOWLEDGEMENT

Action Item 1e. - Capacity Contribution

Track and report the statistics used to calculate capacity contribution from wind 

resources and available solar information as a means of testing the validity of the peak 

load carrying capability (PLCC) method.

DOES NOT REQUIRE ACKNOWLEDGEMENT

2. Distributed Generation Actions

Action Item 2a. - Distributed Solar

Manage the expanded Utah Solar Incentive Program to encourage the installation of the 

entire approved capacity. Beginning in June 2014, as stipulated in the Order in Docket 

No. 11-035-104, the Company will file an Annual Report with program results, system 

costs, and production data. These reports will also provide an opportunity to evaluate 

and improve the program as the Company will use this opportunity to recommend 

changes. Interested parties will have an opportunity to comment on the report and any 

associated recommendations.

Action Item 2b. - Combined Heat & Power (CHP)

Pursue opportunities for acquiring CHP resources, primarily through the Public Utilities 

Regulatory Policies Act PURPA Qualifying Facility contracting process. For the 2013 

IRP Update, complete a market analysis of CHP opportunities that will: (1) assess the 

existing, proposed, and potential generation sites on PacifiCorp’s system; (2) assess 

availability of fuel based on market information; (3) review renewable resource site 

information (i.e. permits, water availability, and incentives) using available public 

information; and (4) analyze indicative project economics based on avoided cost pricing 

to assist in ranking probability of development.

DOES NOT REQUIRE ACKNOWLEDGEMENT

3. Firm Market Purchase Actions

Action Item 3a. - Front Office Transactions

Acquire economic front office transactions or power purchase agreements as needed 

through the summer of 2017.

– Resources will be procured through multiple means, such as periodic market RFPs

that seek resources less than five years in term, and bilateral negotiations.

– Include in the 2013 IRP Update a summary of the progress the Company has made to 

acquire front office transactions over the 2014 to 2017 forward period.

DOES NOT REQUIRE ACKNOWLEDGEMENT

4. Flexible Resource Actions

Action Item 4a. - Energy Imbalance Market (EIM)
LC 57 Attachment B – Staff’s proposed redline changes to action items

March 4, 2014

Page 3

3

Continue to pursue the EIM activities with the California Independent System Operator 

and the Northwest Power Pool to further optimize existing resources resulting in 

reduced costs for customers.

DOES NOT REQUIRE ACKNOWLEDGEMENT

5. Hedging Actions

Action Item 5a. - Natural Gas Request for Proposal

Convene a workshop for stakeholders by October 2013 to discuss potential changes to 

the Company’s process in evaluating bids for future natural gas RFPs, if any, to secure 

additional long-term natural gas hedging products.

DOES NOT REQUIRE ACKNOWLEDGEMENT

6. Plant Efficiency Improvement Actions

Action Item 6a. - Plant Efficiency Improvements

Production efficiency studies have been conducted to satisfy requirements of the 

Washington I-937 Production Efficiency Measure that have identified categories of cost 

effective production efficiency opportunity.

– By the end of the first quarter of 2014, complete an assessment of the plant

efficiency opportunities identified in the Washington I-937 studies that might be 

applicable to other wholly owned generation facilities.

– Prior to initiating modeling efforts for the 2015 IRP, determine a multi-state 

“total resource cost test” evaluation methodology to address regulatory recovery 

among states with identified capital expenditures.

– Prior to initiating modeling efforts for the 2015 IRP, present to IRP stakeholders 

in a public input meeting the Company’s recommended approach to analyzing 

cost effective production efficiency resources in the 2015 IRP.

7. Demand Side Management (DSM) Actions

ACKNOWLEDGE AS REVISED

Action Item 7a. - Class 2 DSM

Acquire 1,425 – 1,876 GWh of cost-effective Class 2 energy efficiency resources by the 

end of 2015 and 2,034 – 3,180 GWh by the end of 2017.

 Collaborate with the Energy Trust of Oregon on a pilot residential home 

comparison report program to be offered to Pacific Power customers in 2013 and 

2014. At the conclusion of the pilot program and the associated impact 

evaluation, assess further expansion of the program.

 Implement an enhanced consolidated business program to increase DSM 

acquisition from business customers in all states excluding Oregon.

o Utah base case schedule is 1st quarter 2014 with an accelerated target of 3rd

quarter 2013.

o Washington base case schedule is 4th quarter 2014, with an accelerated 

target of 1st quarter 2014.
LC 57 Attachment B – Staff’s proposed redline changes to action items

March 4, 2014

Page 4

4

o Wyoming, California, and Idaho base case schedule is 4th quarter 2014, with 

an accelerated target of 2nd quarter 2014.

 Accelerate to the 2nd quarter of 2014, an evaluation of waste heat to power 

where generation is used to offset customer requirements – investigate how to 

integrate opportunities into the DSM portfolio.

 Increase acquisitions from business customers through prescriptive measures by 

expanding the “Trade Ally Network”.

o Base case target in all states is 3rd quarter 2014, with an accelerated target 

of 4th quarter 2013

 Accelerate small-mid market business DSM acquisitions by contracting with third 

party administrators to facilitate greater acquisitions by increasing marketing, 

outreach, and management of comprehensive custom projects by 1st quarter 

2014.

 Increase the reach and effectiveness of “express” or “typical” measure offerings 

by increasing qualifying measures, reviewing and realigning incentives, 

implementing a direct install feature for small commercial customers, and 

expanding the residential refrigerator and freezer recycling program to include 

commercial units.

o Utah base case schedule is 1st quarter 2014 with an accelerated target of 3rd

quarter 2013.

o Washington base case schedule is 4th quarter 2014, with an accelerated 

target of 1st quarter 2014.

o Wyoming, California, and Idaho base case schedule is 4th quarter 2014, with 

an accelerated target of 2nd quarter 2014.

 Increase the reach of behavioral DSM programs:

o Evaluate and expand the residential behavioral pilot.

o Utah base case schedule is 2nd quarter 2014, with an accelerated 

target of 4th quarter 2013.

o Accelerate commercial behavioral pilot to the end of the first quarter 2014.

o Expand residential programs system-wide pending evaluation results.

o System-wide target is 3rd quarter 2015, with an accelerated target of 

3rd quarter 2014.

 Increase acquisition of residential DSM resources:

o Implement cost effective direct install options by the end of 2013.

o Expand offering of “bundled” measure incentives by the end of 2013.

o Increase qualifying measures by the end of 2013.

o Review and realign incentives.

o Utah schedule is 1st quarter 2014

o Washington base case schedule is 2nd quarter 2014, with accelerated 

target of 1st quarter 2014.

o Wyoming, California, and Idaho base case schedule is 3rd quarter 

2014, with an accelerated target of 2nd quarter 2014

o Accelerate acquisitions by expanding refrigerator and freezer recycling to 

incorporate retail appliance distributors and commercial units – 3rd quarter 

2013.
LC 57 Attachment B – Staff’s proposed redline changes to action items

March 4, 2014

Page 5

5

o By the end of 2013, complete review of the impact of accelerated DSM on

Oregon and the Energy Trust of Oregon, and re-contract in 2014 for 

appropriate funding as required.

o Include in the 2013 IRP Update Class 2 DSM decrement values based upon

accelerated acquisition of DSM resources.

o Include in the 2014 conservation potential study an analysis testing 

assumptions in support of accelerating acquisition of cost-effective Class 2 

DSM resources, and apply findings from this analysis into the development of 

candidate portfolios in the 2015 IRP.

 Provide twice yearly updates on the status of DSM IRP acquisition goals to the 

Oregon Commission in 2014 and 2015 at regular public meetings. Summarize 

where efforts have deviated from previously agreed upon action items and report 

on progress toward specific DSM targets for all states other than Oregon. As 

part of these updates, provide information on progress in exploring energy 

efficiency opportunities with special contract customers in next round of contract 

negotiations.

 Include in the 2014 conservation potential study an Implementation Plan specific 

to PacifiCorp service territory for all states other than Oregon which quantifies

how much Class 2 DSM programs can be accelerated and how much it will cost 

to accelerate acquisition.

 In the 2015 IRP and in quarterly updates, report back on the status of negotiating 

energy efficiency projects with special contract customers.

 Going forward, in future IRPs, the Company will provide yearly Class 1 and Class 

2 DSM acquisition targets in both GWh and MW for each year in the planning 

period, by state.

DOES NOT REQUIRE ACKNOWLEDGEMENT

Action Item 7b. - Class 3 DSM

Develop a pilot program in Oregon for a Class 3 irrigation time-of-use program as an 

alternative approach to a Class 1 irrigation load control program for managing irrigation 

loads in the west. The pilot program will be developed for the 2014 irrigation season and 

findings will be reported in the 2015 IRP.

8. Coal Resource Actions

ACKNOWLEDGE AS REVISED

Action Item 8a. - Naughton Unit 3

– Continue permitting and development efforts in support of the Naughton Unit 3 

natural gas conversion project. The permit application requesting operation on 

coal through year-end 2017 is currently under review by the Wyoming 

Department of Environmental Quality, Air Quality Division. 
LC 57 Attachment B – Staff’s proposed redline changes to action items

March 4, 2014

Page 6

6

– Issue a request for proposal to procure gas transportation for the Naughton plant 

as required to support compliance with the conversion date that will be 

established during the permitting process.

– Issue an RFP for engineering, procurement, and construction of the Naughton 

Unit 3 natural gas retrofit as required to support compliance with the conversion 

date that will be established during the permitting process.

– Evaluate the Naughton Unit 3 investment decision in the 2015 IRP with updated 

analysis including the shutdown versus conversion options.

RECOMMEND NOT ACKNOWLEDGE

Action Item 8b. - Hunter Unit 1

Complete installation of the baghouse conversion and low NOX burner compliance 

projects at Hunter Unit 1 as required by the end of 2014.

ACKNOWLEDGE AS PROPOSED

Action Item 8c. - Jim Bridger Units 3 and 4

Complete installation of selective catalytic reduction (SCR) compliance projects at Jim 

Bridger Unit 3 and Jim Bridger Unit 4 as required by the end of 2015 and 2016, 

respectively.

ACKNOWLEDGE AS REVISED 

Action Item 8d. - Cholla Unit 4

Continue to evaluate alternative compliance strategies that will meet Regional Haze 

compliance obligations, related to the U.S. Environmental Protection Agency’s Federal 

Implementation Plan requirements to install SCR equipment at Cholla Unit 4. Provide 

an update of the analysis of Cholla Unit 4 analysis regarding compliance alternatives in 

the 2013 IRP Update in a special designated IRP Update within six months of the final 

order in LC 57 and well enough in advance to allow for all potential reasonable pollution 

control alternatives for Cholla to be adequately pursued.

NEW ACTION ITEM

Action Item 8e. – Craig and Hayden

Within three months of the Commission order in this docket PacifiCorp shall schedule a 

confidential technical workshop to review existing analysis on the planned Craig and 

Hayden environmental investments. 

NEW ACTION ITEM

Action Item 8f. - Wyodak

For the 2015 IRP the following inter-temporal and fleet trade-off analysis related to the 

SCR requirement on Wyodak by 2019 will be used as a frame of reference:
LC 57 Attachment B – Staff’s proposed redline changes to action items

March 4, 2014

Page 7

7

Inter-temporal Scenarios

EPA 

requirement Time 1 Time 2 Time 3

Wyodak 

Plant 

Action

SCR 

Retrofit

SNCR 

Retrofit / 

early 

retirement

Gas 

Conversion Retirement

Timeline 2019 2019 /2030 2022 2027

Fleet Trade-Off Scenarios 

EPA requirement Fleet 1 Fleet 2 Fleet 3 Fleet 4

Wyodak SCR Retrofit in 

2019 No Action No Action No Action No Action

Dave Johnston 

Units 1 & 2 No Action Retirement in 2027 No Action

Gas 

Conversion 

in 2022

No Action

Dave Johnston 

Unit 4 No Action No Action Retirement in 2027 No Action

Gas 

Conversion 

in 2022

 The timing and options will be finalized with stakeholders at the workshops for 

the 2015 IRP.

 This analysis will include considerations for the necessity of Gateway West with 

reduced capacity in eastern Wyoming.

 Workshops will be held, including at least one with the Commissioners, to refine 

the list of specific fleet analyses to be performed in the IRP. Staff will bring final 

recommendations to the Commission at a Public Meeting and the Company and 

parties will have an opportunity to respond. 

NEW ACTION ITEM

Action Item 8g. – Carbon Analysis

Prior to the end of 2014, the Company will work with Staff and stakeholders to explore 

options for how the Company plans to model and perform analysis in the 2015 IRP 

related to what is known about the requirements of Section 111(d).
LC 57 Attachment B – Staff’s proposed redline changes to action items

March 4, 2014

Page 8

8

NEW ACTION ITEM

Action Item 8h. – Screening Tool

As part of the 2015, 2017, and 2019 IRP, the Company shall provide an updated 

version of the confidential screening tool spreadsheet model that was provided to Staff 

and parties as part of the LC 52 2011 IRP Update

NEW ACTION ITEM

Action Item 8i. – Timelines

As part of future IRPs, the Company shall provide documentation of timelines and key 

decision points for expected pollution control options.

NEW ACTION ITEM

Action Item 8j. – Planned expenditures

As part of future IRPs, the Company shall provide tables detailing major planned 

expenditures with estimated cost in each year for each generating facility, under 

different modeled scenarios.

NEW ACTION ITEM

Action Item 8k. – Quarterly updates

Following the issuance of the final Commission order in this IRP, starting in the third 

quarter of 2014, the Company shall come before the Commission at a public meeting 

and make quarterly updates on coal plant compliance requirements, legal proceedings, 

pollution control investments, and other major capital expenditures at the Company’s 

coal plants.

9. Transmission Actions

DOES NOT REQUIRE ACKNOWLEDGEMENT

Action Item 9a. - System Operational and Reliability Benefits Tool (SBT)

60 days after filing the 2013 IRP, establish a stakeholder group and schedule 

workshops to further review the System

Benefit Tool (SBT).

– For the 2013 IRP Update, complete additional analysis of the Energy Gateway 

West Segment D that evaluates staging implementation of Segment D by subsegment.

– In preparation for the 2015 IRP, continue to refine the SBT for Energy Gateway 

West Segment D and develop SBT analyses for additional Energy Gateway 

segments.

ACKNOWLEDGE AS REVISED

Action Item 9b. - Energy Gateway Permitting

Continue permitting Segments D, E, F, and H until PacifiCorp files its 2015 IRP, 

when SBT analyses for these segments will be performed.
LC 57 Attachment B – Staff’s proposed redline changes to action items

March 4, 2014

Page 9

9

Continue permitting for the Energy Gateway transmission plan, with near term 

targets as follows:

– Segment D, E, and F, continue funding of the required federal agency 

permitting environmental consultant as actions to achieve final federal permits.

– Segment D, E, and F, continue to support the federal permitting process by 

providing information and participating in public outreach projected through the 

next 2 to 4 years.

– Segment H Cascade Crossing, complete benefits analysis in 2013.

– Segment H Boardman to Hemingway, continue to support the project under the 

conditions of the Boardman to Hemingway Transmission. Project Joint Permit 

Funding Agreement, projected through 2015.

ACKNOWLEDGE AS PROPOSED

Action Item 9c. - Sigurd to Red Butte 345 kilovolt Transmission Line

Complete project construction per plan.

DOES NOT REQUIRE ACKNOWLEDGEMENT

10.Planning Reserve Margin Actions

Action Item 10a. - Planning Reserve Margin

Continue to evaluate in the 2015 IRP the results of a System Optimizer portfolio 

sensitivity analysis comparing a range of planning reserve margins considering both 

cost and reliability impacts of different levels of planning reserve margin assumptions. 

Complete for the 2015 IRP an updated planning reserve margin analysis that is shared 

with stakeholders during the public process.

DOES NOT REQUIRE ACKNOWLEDGEMENT

11.Planning and Modeling Process Improvement Actions

Action Item 11a. - Modeling and Process

Within 90 days of filing the 2013 IRP, schedule an IRP workshop with stakeholders to 

discuss potential process improvements that can more efficiently achieve meaningful 

cost and risk analysis of resource plans in the context of the IRP and implement 

process improvements in the 2015 IRP.

DOES NOT REQUIRE ACKNOWLEDGEMENT

Action Item 11b. - Cost/Benefit Analysis of DSM Resource Alternatives

Complete a cost/benefit analysis on the level of detail used to evaluate prospective 

DSM resources in the IRP. The analysis will consider the tradeoffs between model runtime and resulting resource selections, will be shared with stakeholders early in the 

2015 IRP public process, and will inform how prospective DSM resources will be 

aggregated in developing resource portfolios for the 2015 IRP.
Attachment C

LC 57 Staff’s Modified Action Items – CLEAN LIST

Renewable Resource Actions

Action Item 1b. - Renewable Portfolio Standard Compliance

With renewable portfolio standard (RPS) compliance achieved with unbundled 

renewable energy credit (REC) purchases, the preferred portfolio does not include 

incremental renewable resources prior to 2024. Given that the REC market lacks 

liquidity and depth beyond one year forward, the Company will pursue unbundled REC 

requests for proposal (RFP) to meet its state RPS compliance requirements.

– Issue at least annually, RFPs seeking then current-year or forward-year vintage 

unbundled RECs that will qualify in meeting Washington renewable portfolio 

standard obligations.

– Issue at least annually, RFPs seeking historical, then current-year, or forwardyear vintage unbundled RECs that will qualify for Oregon renewable portfolio 

standard obligations. As part of the solicitation and bid evaluation process, 

evaluate the tradeoffs between acquiring bankable RECs early as a means to 

mitigate potentially higher cost long-term compliance alternatives.

– Issue at least annually, RFPs seeking then current-year or forward-year vintage 

unbundled RECs that will qualify for California renewable portfolio standard 

obligations.

Action Item 1d. - Solar

– Issue an RFP in the second quarter of 2013 soliciting Oregon solar photovoltaic 

resources to meet the Oregon small solar compliance obligation (Oregon House 

Bill 3039). Coordinate the selection process with the Energy Trust of Oregon to 

seek 2014 project funding. Complete evaluation of proposals and select potential 

winning bids in the fourth quarter of 2013.

– Issue a request for information 180 days after filing the 2013 IRP to solicit 

updated market information on utility scale solar cost

Demand Side Management (DSM) Actions

Action Item 7a. - Class 2 DSM

Acquire 1,425 – 1,876 GWh of cost-effective Class 2 energy efficiency resources by the 

end of 2015 and 2,034 – 3,180 GWh by the end of 2017.

 Collaborate with the Energy Trust of Oregon on a pilot residential home 

comparison report program to be offered to Pacific Power customers in 2013 and 

2014. At the conclusion of the pilot program and the associated impact 

evaluation, assess further expansion of the program.

 Implement an enhanced consolidated business program to increase DSM 

acquisition from business customers in all states excluding Oregon.

o Utah base case schedule is 1st quarter 2014 with an accelerated target of 3rd

quarter 2013.
LC 57 Attachment C – Staff’s Modified Action Items – Clean List

March 4, 2014

Page 2

2

o Washington base case schedule is 4th quarter 2014, with an accelerated 

target of 1st quarter 2014.

o Wyoming, California, and Idaho base case schedule is 4th quarter 2014, with 

an accelerated target of 2nd quarter 2014.

 Accelerate to the 2nd quarter of 2014, an evaluation of waste heat to power 

where generation is used to offset customer requirements – investigate how to 

integrate opportunities into the DSM portfolio.

 Increase acquisitions from business customers through prescriptive measures by 

expanding the “Trade Ally Network”.

o Base case target in all states is 3rd quarter 2014, with an accelerated target 

of 4th quarter 2013

 Accelerate small-mid market business DSM acquisitions by contracting with third 

party administrators to facilitate greater acquisitions by increasing marketing, 

outreach, and management of comprehensive custom projects by 1st quarter 

2014.

 Increase the reach and effectiveness of “express” or “typical” measure offerings 

by increasing qualifying measures, reviewing and realigning incentives, 

implementing a direct install feature for small commercial customers, and 

expanding the residential refrigerator and freezer recycling program to include 

commercial units.

o Utah base case schedule is 1st quarter 2014 with an accelerated target of 3rd

quarter 2013.

o Washington base case schedule is 4th quarter 2014, with an accelerated 

target of 1st quarter 2014.

o Wyoming, California, and Idaho base case schedule is 4th quarter 2014, with 

an accelerated target of 2nd quarter 2014.

 Increase the reach of behavioral DSM programs:

o Evaluate and expand the residential behavioral pilot.

o Utah base case schedule is 2nd quarter 2014, with an accelerated 

target of 4th quarter 2013.

o Accelerate commercial behavioral pilot to the end of the first quarter 2014.

o Expand residential programs system-wide pending evaluation results.

o System-wide target is 3rd quarter 2015, with an accelerated target of 

3rd quarter 2014.

 Increase acquisition of residential DSM resources:

o Implement cost effective direct install options by the end of 2013.

o Expand offering of “bundled” measure incentives by the end of 2013.

o Increase qualifying measures by the end of 2013.

o Review and realign incentives.

o Utah schedule is 1st quarter 2014

o Washington base case schedule is 2nd quarter 2014, with accelerated 

target of 1st quarter 2014.

o Wyoming, California, and Idaho base case schedule is 3rd quarter 

2014, with an accelerated target of 2nd quarter 2014
LC 57 Attachment C – Staff’s Modified Action Items – Clean List

March 4, 2014

Page 3

3

o Accelerate acquisitions by expanding refrigerator and freezer recycling to 

incorporate retail appliance distributors and commercial units – 3rd quarter 

2013.

o By the end of 2013, complete review of the impact of accelerated DSM on 

Oregon and the Energy Trust of Oregon, and re-contract in 2014 for 

appropriate funding as required.

o Include in the 2013 IRP Update Class 2 DSM decrement values based upon 

accelerated acquisition of DSM resources.

o Include in the 2014 conservation potential study an analysis testing 

assumptions in support of accelerating acquisition of cost-effective Class 2 

DSM resources, and apply findings from this analysis into the development of 

candidate portfolios in the 2015 IRP.

 Provide twice yearly updates on the status of DSM IRP acquisition goals to the 

Oregon Commission in 2014 and 2015 at regular public meetings. Summarize 

where efforts have deviated from previously agreed upon action items and report 

on progress toward specific DSM targets for all states other than Oregon. As 

part of these updates, provide information on progress in exploring energy 

efficiency opportunities with special contract customers in next round of contract 

negotiations.

 Include in the 2014 conservation potential study an Implementation Plan specific 

to PacifiCorp service territory for all states other than Oregon which quantifies

how much Class 2 DSM programs can be accelerated and how much it will cost 

to accelerate acquisition.

 In the 2015 IRP and in quarterly updates, report back on the status of negotiating 

energy efficiency projects with special contract customers.

 Going forward, in future IRPs, the Company will provide yearly Class 1 and Class 

2 DSM acquisition targets in both GWh and MW for each year in the planning 

period, by state.

Coal Resource Actions

Action Item 8a. - Naughton Unit 3

– Continue permitting and development efforts in support of the Naughton Unit 3 

natural gas conversion project. The permit application requesting operation on 

coal through year-end 2017 is currently under review by the Wyoming 

Department of Environmental Quality, Air Quality Division. 

– Issue a request for proposal to procure gas transportation for the Naughton plant 

as required to support compliance with the conversion date that will be 

established during the permitting process.
LC 57 Attachment C – Staff’s Modified Action Items – Clean List

March 4, 2014

Page 4

4

– Issue an RFP for engineering, procurement, and construction of the Naughton 

Unit 3 natural gas retrofit as required to support compliance with the conversion 

date that will be established during the permitting process.

– Evaluate the Naughton Unit 3 investment decision in the 2015 IRP with updated 

analysis including the shutdown versus conversion options.

Action Item 8c. - Jim Bridger Units 3 and 4

Complete installation of selective catalytic reduction (SCR) compliance projects at Jim 

Bridger Unit 3 and Jim Bridger Unit 4 as required by the end of 2015 and 2016, 

respectively.

Action Item 8d. - Cholla Unit 4

Continue to evaluate alternative compliance strategies that will meet Regional Haze 

compliance obligations, related to the U.S. Environmental Protection Agency’s Federal 

Implementation Plan requirements to install SCR equipment at Cholla Unit 4. Provide 

an analysis of Cholla Unit 4 compliance alternatives in a special designated IRP Update 

within six months of the final order in LC 57 and well enough in advance to allow for all 

potential reasonable pollution control alternatives for Cholla to be adequately pursued.

Action Item 8e. – Craig and Hayden

Within three months of the Commission order in this docket PacifiCorp shall schedule a 

confidential technical workshop to review existing analysis on the planned Craig and 

Hayden environmental investments. 

Action Item 8f. - Wyodak

For the 2015 IRP the following inter-temporal and fleet trade-off analysis related to the 

SCR requirement on Wyodak by 2019 will be used as a frame of reference:

Inter-temporal Scenarios

EPA 

requirement Time 1 Time 2 Time 3

Wyodak 

Plant 

Action

SCR 

Retrofit

SNCR 

Retrofit / 

early 

retirement

Gas 

Conversion Retirement

Timeline 2019 2019 /2030 2022 2027
LC 57 Attachment C – Staff’s Modified Action Items – Clean List

March 4, 2014

Page 5

5

Fleet Trade-Off Scenarios 

EPA requirement Fleet 1 Fleet 2 Fleet 3 Fleet 4

Wyodak SCR Retrofit in 

2019 No Action No Action No Action No Action

Dave Johnston 

Units 1 & 2 No Action Retirement in 2027 No Action

Gas 

Conversion 

in 2022

No Action

Dave Johnston 

Unit 4 No Action No Action Retirement in 2027 No Action

Gas 

Conversion 

in 2022

 The timing and options will be finalized with stakeholders at the workshops for 

the 2015 IRP.

 This analysis will include considerations for the necessity of Gateway West with 

reduced capacity in eastern Wyoming.

 Workshops will be held, including at least one with the Commissioners, to refine 

the list of specific fleet analyses to be performed in the IRP. Staff will bring final 

recommendations to the Commission at a Public Meeting and the Company and 

parties will have an opportunity to respond. 

Action Item 8g. – Carbon Analysis

Prior to the end of 2014, the Company will work with Staff and stakeholders to explore 

options for how the Company plans to model and perform analysis in the 2015 IRP 

related to what is known about the requirements of Section 111(d).

Action Item 8h. – Screening Tool

As part of the 2015, 2017, and 2019 IRP, the Company shall provide an updated 

version of the confidential screening tool spreadsheet model that was provided to Staff 

and parties as part of the LC 52 2011 IRP Update.

Action Item 8i. – Timelines

As part of future IRPs, the Company shall provide documentation of timelines and key 

decision points for expected pollution control options.

Action Item 8j. – Planned expenditures

As part of future IRPs, the Company shall provide tables detailing major planned 

expenditures with estimated cost in each year for each generating facility, under 

different modeled scenarios.

Action Item 8k. – Quarterly updates

Following the issuance of the final Commission order in this IRP, starting in the third 

quarter of 2014, the Company shall come before the Commission at a public meeting

and make quarterly updates on coal plant compliance requirements, legal proceedings, 
LC 57 Attachment C – Staff’s Modified Action Items – Clean List

March 4, 2014

Page 6

6

pollution control investments, and other major capital expenditures at the Company’s 

coal plants.

Transmission Actions

Action Item 9b. - Energy Gateway Permitting

Continue permitting Segments D,E, F, and H until PacifiCorp files its 2015 IRP, when 

SBT analyses for these segments will be performed.

Action Item 9c. - Sigurd to Red Butte 345 kilovolt Transmission Line

Complete project construction per plan.