ALJ/MLC/Tcg

ALJ/GK1/jt2 Date of Issuance 5/8/2017

BEFORE THE PUBLIC UTILITIES COMMISSION OF THE STATE OF CALIFORNIA

Order Instituting Investigation to determine whether PacifiCorp (U901E) engages in FILED leastcost planning on a control area basis and PUBLIC UTILITIES COMMISSION whether PacifiCorp’s InterJurisdictional Cost APRIL 27, 2017 Allocation Protocol results in just and SAN FRANCISCO, CALIFORNIA reasonable rates in California. INVESTIGATION 17-04-019

ORDER INSTITUTING INVESTIGATION

184960528 1 I.17-04-019 ALJ/GK1/jt2

Table of Contents

Title Page

Attachment 1 - PacifiCorp’s Retail Service Territories as of December 31, 2014

2 ORDER INSTITUTING INVESTIGATION

Summary This Order Instituting Investigation (OII) is opened on the Commission’s own motion pursuant to Rule 5.1 of the Commission’s Rules of Practice and Procedure. The purpose of this OII is to examine generation and transmission resources in PacifiCorp’s Western and Eastern control areas to determine whether PacifiCorp engages in leastcost planning and dispatch on a systemwide or control area basis, and whether PacifiCorp’s InterJurisdictional Cost Allocation Protocol results in just and reasonable rates in California. This investigation may develop an interjurisdictional cost allocation method for PacifiCorp in California, and it may also inform the Commission’s consideration of PacifiCorp’s 2019 test year general rate case and the Commission’s viewpoints on the Public Utility Commission of Oregon’s activities to evaluate alternatives to PacifiCorp’s existing corporate structure. Additionally, this investigation will audit PacifiCorp’s compliance with the Greenhouse Gases Emission Performance Standard. These issues may result in directives to PacifiCorp that serve the public interest and result in just and reasonable rates. PacifiCorp (U901E) is named as a respondent to this OII; however, the Commission expects and welcomes involvement and input from a wide range of interested entities to inform its decisionmaking process. Responses to the proposed scope, schedule, and need for hearings are due 30 days after adoption of this OII by the Commission.

1. Background PacifiCorp is a multijurisdictional investorowned public utility engaged in the business of providing electric retail service in portions of Northern California and in the states of Oregon, Washington, Utah, Idaho and Wyoming. PacifiCorp operates under the trade name Pacific Power in Oregon, Washington and California, and under the trade name Rocky Mountain Power in Utah, Wyoming and Idaho. PacifiCorp serves approximately 45,000 retail electric customers in California,1 which accounts for approximately one percent of PacifiCorp’s total retail electricity sales across all states in which it operates.2

1 PacifiCorp Advice Letter 549E, filed February 1, 2017. 3 1.1. 1988 Merger of PacifiCorp Maine and Utah Power & Light Company In 1987, PacifiCorp (a Maine corporation) and Utah Power & Light Company (Utah Power), a Utah corporation, proposed to merge into a new company, PacifiCorp (an Oregon corporation).3 The California Public Utilities Commission (Commission) approved this merger in Decision (D.) 8804062. At the time of the merger, PacifiCorp Maine provided electric service to approximately 670,000 customers in California, Washington, Oregon, Idaho, and Montana, and Utah Power provided electric service to approximately 510,000 customers in Utah, Idaho and Wyoming.4 When approving the merger, the Commission noted that California customers were expected to provide 2.56 percent of the newly formed PacifiCorp Oregon’s total electric revenues.5 As recounted in D.8804062, PacifiCorp’s testimony in support of its merger application asserted that benefits would accrue to customers in part through Utah Power’s substantial transmission network and access to wholesale markets unavailable to Pacific Power. PacifiCorp testimony also stated that the proposed merged utility had no detailed proposal for the interjurisdictional or interclass allocation of costs and revenues.6 The Commission’s then Division of Ratepayer Advocates (now Office of Ratepayer Advocates, (ORA)) recommended approval of the proposed merger on the condition that PacifiCorp reconvene an Allocation Committee, with representatives of each state served by PacifiCorp, to develop a proposed cost and revenue allocation methodology to the Commission. ORA expressed concern that rate reductions that PacifiCorp promised to Utah ratepayers should not be subsidized with savings and benefits that are more properly assigned to other jurisdictions such as California.7 The Commission approved the merger, prohibited PacifiCorp from requesting an increase in overall average rates for

2 Berkshire Hathaway Energy Company, Securities and Exchange Commission Form 10K, 2015 Annual Report at 3. 3 See Application (A.) 8709043. 4 D.8804062 at 2. See, Attachment 1, for PacifiCorp’s Retail Service Territories as of December 1, 2014. 5 Id. 6 Id., at 4. 7 Id., at 5. 4 1988 through 1991, and required PacifiCorp to convene an Allocation Committee to determine a fair allocation among the various jurisdictions.8

1.2. Subsequent Acquisitions The Commission authorized ScottishPower to acquire PacifiCorp in D.9906049. At the time, PacifiCorp’s California service territory represented 3.3 percent of PacifiCorp’s retail customers and 2 percent of retail electricity sales systemwide.9 PacifiCorp was subsequently acquired by MidAmerican Energy Holdings Company, authorized in D.0602033, and PacifiCorp is presently an indirect wholly owned subsidiary of Berkshire Hathaway Energy.

1.3. General Rate Cases and InterJurisdictional Cost Allocation Since the 1988 merger between PacifiCorp and Utah Power, PacifiCorp appears to have filed applications for only two general rate cases (GRC) – for the 2007 and 2011 test years. In neither case did the Commission evaluate the reasonableness of how PacifiCorp allocates costs and revenues among the six states in which it operates.

1.3.1. 2007 GRC The Commission approved PacifiCorp’s 2007 test year GRC in D.0612011 by adopting an unopposed settlement between PacifiCorp and ORA. That decision adopted a revenue allocation and rate design settlement and authorized PacifiCorp to implement an energy cost adjustment clause (ECAC) balancing account and a posttest year adjustment mechanism (PTAM). D.0612011 explains that PacifiCorp requested an ECAC “so that it could recover its volatile energy cost in a timely and efficient manner. It requested a PTAM so that it could timely recover prudently incurred cost increases related to inflation, new plant, general operating cost increases, unforeseen events, and changes in its capital structure without filing a GRC.”10 D.0612011 evaluated and approved the reasonableness of the proposed settlement agreement, but it did not assess the reasonableness of PacifiCorp’s InterJurisdictional Cost Allocation Protocol (Revised Protocol), the method by which PacifiCorp allocates

8 Id., at 9. 9 D.9906049 at 16. 10 D.0612011 at 3. 5 costs and revenues among the six states of its service territory for the purpose of setting retail rates. The settlement agreement states that all elements of [the 2007 test year revenue requirement rate case]…shall be based on the Revised Protocol allocation methodology. In its next general rate case, PacifiCorp shall apply the same approach ordered by the Public Utility Commission of Oregon in Order No. 05021 (January 12, 2005) with respect to the requirement that the filing include the Hybrid model allocation methodology as a comparison to the Revised Protocol allocation methodology.11

The settlement did not further define the Revised Protocol or the “Hybrid model.”

1.3.2. InterJurisdictional Cost Allocation in Oregon and Washington The Public Utility Commission of Oregon (PUC of Oregon) ratified the Revised Protocol in Order No. 05021; however, it also required PacifiCorp to devise a fully functional Hybrid Method and file annual reports and general rate case filings using both the Revised Protocol and the Hybrid Method as comparators. At a conceptual level, the Revised Protocol and the Hybrid Method differ in a fundamental way: the Revised Protocol assumes that PacifiCorp serves customers in the sixstate region from a common resource portfolio; and the Hybrid Method assumes that PacifiCorp operates as two largely independent control areas for the purpose of ratemaking – a Western control area, and an Eastern control area. The Oregon order states about the Revised Protocol that:

The Revised Protocol is a document describing how costs and wholesale revenues associated with PacifiCorp’s generation, transmission, and distribution systems will be allocated among the six states. The Revised Protocol does not establish the prudence of any cost related to the allocation of an expense or investment to a particular state. Rather, the prudence of a specific cost is left to each state to determine during future regulatory proceedings.

…Although the Joint Parties intend the terms of the Revised Protocol to be enduring, changed or unforeseen circumstances may occur which require a party to conclude in good faith that the Revised Protocol no longer produces results that are just and reasonable, or in the public interest. In that event, a party will no longer be bound to support the Revised Protocol.12

11 D.0612011, Attachment A, at 6. 12 PUC of Oregon, Order No. 05021 at 3. 6 The Oregon order also explains the “Hybrid Method,” which PacifiCorp agreed to provide as a comparison to the Revised Protocol in its next California GRC: The Hybrid Method divides the generation system into two regions (East and West) for regulatory accounting purposes. Oregon, Washington and California comprise the West Region, while Utah, Wyoming, and Idaho comprise the East Region. Each state’s load, each PacifiCorpowned resource, and most of the contracts are assigned to a Region. Under this methodology, most of PacifiCorp’s existing hydroelectric resources and the majority of longterm power purchases would be assigned to the West Region. The states in each Region would set rates to recover the costs of the generating resources assigned to their Region.

The Hybrid Method includes a process to allocate costs and revenues associated with system balancing purchases/sales and interchanges deemed to be made between the regions. There is also a process for sharing operational reserves between the regions.

The loads in the East Region are forecasted to grow faster than those in the West Region. Utilization of the Hybrid Method would eliminate the concern that West Region customers, such as Oregon, would subsidize the forecasted load growth in the East Region.

The Hybrid Method was developed by a workgroup consisting of representatives from this Commission, the Utah Division of Public Utilities, the Idaho Public Utilities Commission, and PacifiCorp. Because this allocation method was unacceptable to the Utah parties, the assumptions and implementation details were never agreed upon by all states involved in the [multistate process (MSP)].13

The PUC of Oregon last approved PacifiCorp’s Revised Protocol in Order No. 16319, which approved a “2017 Protocol” for use through 2018;14 however, in Order No. 17124, issued March 29, 2017, the PUC of Oregon extended the 2017 Protocol for use through 2019 and simultaneously opened a new docket, UM 1824, a staffled investigation to explore cost allocation approaches consistent with costcausation principles that are reasonable for Oregon customers.15 When explaining its intent to open a new investigation into interjurisdictional cost allocation issues, the PUC of Oregon stated that “Oregon will be facing new and unique allocation issues due to the passage of

13 PUC of Oregon Order No. 05021 at 5. 14 See http://apps.puc.state.or.us/orders/2016ords/16319.pdf. 15 PUC of Oregon, Order No. 17124, at 4, available at http://apps.puc.state.or.us/orders/2017ords/17124.pdf. 7 [Senate Bill] 1547 which, in part, requires the removal of coal resources from Oregon rates by 2030.”16 Shortly before the Commission issued D.0612011 adopting the 2007 test year GRC settlement for California customers, the Washington Utilities and Transportation Commission (Washington UTC) considered and rejected PacifiCorp’s proposal to use the Revised Protocol as an interjurisdictional cost allocation method for use in Washington, concluding that PacifiCorp has not met its burden of proof to show that resources allocated to Washington in the Revised Protocol are used and useful for service in this state, a requirement of Washington statute.17 In a 2007 order, the Washington UTC subsequently approved a fullydeveloped West Control Area (WCA) interjurisdictional cost allocation method for PacifiCorp’s Washington customers. Washington’s WCA method is conceptually similar to the Hybrid Model proposed in Oregon. The Washington UTC explained that: The WCA includes the California, Oregon and Washington loads and resources. Some of these generation resources, such as Colstrip and Jim Bridger, are located outside Washington, Oregon and California, but adequate transmission is available for these resources to provide delivery to Washington customers. The WCA method isolates the costs associated with these assets, purchases and sales, and allocates to Washington a proportionate share of the costs based on Washington’s relative contribution to the WCA’s demand and energy requirements.18 1.3.3. 2011 GRC PacifiCorp filed its most recent California GRC, A.0911015, in November 2009 for Test Year 2011. As required in D.0612011, PacifiCorp provided comparative revenue requirements using both the Revised Protocol and the Hybrid method.19 In D.1009010 the Commission approved an all party settlement agreement to resolve PacifiCorp’s 2011 test year GRC. In the settlement, the parties agreed that PacifiCorp will continue to use the Revised Protocol InterJurisdictional Allocation Methodology to

16 PUC of Oregon, Order No. 16319 at 6. 17 Washington Utilities and Transportation Commission, Docket UE050684, Order 04, adopted April 17, 2006, at 21 and 118. 18 Washington UTC Docket UE061546, Order 08 at 13, June 21, 2007. 19 See A.09011015 Exhibit PPL/500 at 8, and Exhibit PPL/502 at Tab 9. 8 determine the revenue requirement for all filings made in California, including but not limited to PTAM, ECAC, and GRC applications.20 Since the 2011 GRC, PacifiCorp has made a series of requests that the Commission grant PacifiCorp a waiver of the threeyear GRC filing cycle. The Commission granted PacifiCorp’s requests to forgo filing a GRC for Test Years 2014 through 2017 and to file PTAM attrition factor rate increases for those years.21 Most recently in D.1609046, the Commission granted PacifiCorp a waiver to forgo filing a GRC for Test Year 2018 and required PacifiCorp’s next GRC to be filed for rates effective January 1, 2019. Additionally, D.1609046 concluded that PacifiCorp may not file a PTAM attrition factor rate increase for 2018 or any PTAMs for coalrelated capital additions during the GRC extension period.

1.4. Change to Electric Market Since the 2011 GRC Since PacifiCorp’s last GRC, the California electric market has changed in two notable ways: 1. The California Air Resources Board (ARB) adopted the California Cap on Greenhouse Gas Emissions and MarketBased Compliance Mechanisms (CapandTrade Program) in December 2011, and the regulation became effective on January 1, 2012.22, 23 As a result of D.1212033 and D.1312041, in April 2014 PacifiCorp’s retail electricity rates in California began to reflect the costs associated with PacifiCorp’s greenhouse gas emissions.

2. The California Independent System Operator launched the Western Energy Imbalance Market (EIM) on November 1, 2014, with PacifiCorp as its first utility participant. 1.5. Emission Performance Standard Senate Bill (SB) 1368 (Stats. 2006) required the Commission to establish a Greenhouse Gases Emission Performance Standard (EPS) for Baseload Electrical

20 See D.1009010 at 12. The Settlement Agreement can be found at http://www.cpuc.ca.gov/EFILE/MOTION/120093.pdf. 21 See D.1210006; D.1307026; D.1406018; and D.1512018. 22 California Code of Regulations (CCR), Title 17, § 95800 et seq. 23 For multijurisdictional retail electricity providers like PacifiCorp, ARB assesses CapandTrade compliance obligations by calculating PacifiCorp’s system emissions factor, which includes emissions from facilities or generating units that contribute to PacifiCorp’s common system power pool. See 17 CCR § 95111(b)(4). 9 Generating Resources.24 SB 1368 specifies that “no loadserving entity or local publicly owned electric utility may enter into a longterm financial commitment unless any baseload generation supplied under [the commitment] complies with the [EPS] established by the commission.” The statute further established the emission rate for these facilities must be no higher than the greenhouse gas (GHG) emissions rate of a combinedcycle gas turbine power plant, to be defined by the Commission. The Commission developed an interim opinion on EPS requirements in D.0701039, which specified an emission limit of 1,100 pounds of carbon dioxide (CO2) per megawatthour (MWh) and clarified the kind of “covered procurements” that are consistent with SB 1368. SB 1368 permits the Commission to consider a showing of “alternative compliance” by multijurisdictional electrical corporations that serve 75,000 or fewer retail enduse customers in California. Specifically, Section 8341(d)(9) states that these load-serving entities: …may file with the commission a proposal for alternative compliance with this section, which the commission may accept upon a showing by the electrical corporation of both of the following:

(A) A majority of the electrical corporation’s retail enduse customers for electric service are located outside of California.

(B) The emissions of greenhouse gases to generate electricity for the retail enduse customers of the electrical corporation are subject to a review by the utility regulatory commission of at least one other state in which the electrical corporation provides regulated retail electric service.

The Commission concluded that an electrical corporation could satisfy part B of SB 1368’s alternative compliance provision when any of the following occur: 1) a state jurisdiction requires the utility to review and report on the potential impacts of different carbon policies within its Integrated Resource Planning process; or 2) when it requires the utility to disclose its GHG emissions or expected change in overall emissions as a result of changes to its portfolio, including new capacity additions; or 3) when a state jurisdiction adopts rules specifically regulating emissions of greenhouse gases from electricity generating facilities.25 The Commission excused PacifiCorp from showing 24 Public Utilities Code Section 83408341. 25 D.0701039 at 165166. 10 compliance with the interim EPS rules based on its showing of alternative compliance. However, the Commission required PacifiCorp to file an annual attestation letter on February 1 of each year stating that it continues to qualify for alternative compliance consistent with D.0701039.26 PacifiCorp most recently filed Advice Letter 549E on February 1, 2017, attesting that it continues to meet alternative compliance requirements consistent with D.0701039, and PacifiCorp has filed similar advice letters every year since 2008. The Commission has not undertaken any investigation to date to assess whether PacifiCorp has been and continues to qualify for alternative compliance with the EPS, as PacifiCorp attests.

2. Preliminary Scope and Issues The primary issue for consideration in this proceeding concerns an investigation into: 1) PacifiCorp’s generation and transmission resources in its Western and Eastern control areas to determine whether PacifiCorp engages in leastcost planning and dispatch on a systemwide or control area basis; 2) whether PacifiCorp’s InterJurisdictional Cost Allocation Protocol results in just and reasonable rates in California; and 3) PacifiCorp’s compliance with the EPS. The proceeding may result in the development of an interjurisdictional cost allocation method for use in setting PacifiCorp’s California rates. Additionally, the information gathered in this investigation will help the Commission evaluate the impacts on California customers of Oregon law requiring PacifiCorp to remove coal resources from Oregon rates by 2030. Lastly, this investigation will help the Commission track and develop viewpoints on the PUC of Oregon’s requirement that PacifiCorp evaluate alternative corporate structures. The preliminary scope of issues and schedule are set forth below. The scope and schedule may be changed by the assigned Commissioner’s Scoping Memo (See Rule 7.3 of the Commission’s Rules of Practice and Procedure (Rules).

2.1. Scope The Commission anticipates undertaking a thorough analysis of the issues listed below. This analysis will be overseen by the Commission’s Energy Division and assisted by appropriately contracted experts if necessary. The preliminary issues the Commission anticipates analyzing are set forth below:

26 Id., Ordering Paragraph 14. 11 1. PacifiCorp Operations on a Control Area Basis a. To what extent does PacifiCorp operate its generation and transmission system as an integrated sixstate system in which customer loads are served from a common pool of resources? a.i. What are PacifiCorp’s different transmission control areas? a.ii. Which generation and transmission resources exist in each control area, and what are their operational characteristics? a.iii. To what extent do transmission constraints limit PacifiCorp from functioning on a fully integrated basis? a.iv. Which resources outside of PacifiCorp’s Western control area provide quantifiable benefits to California electric customers? b. Does PacifiCorp apply leastcost planning and dispatch on a controlarea basis or a systemwide basis? c. Which currently in service PacifiCorp transmission and generation resources in the Western and Eastern control areas predate PacifiCorp’s merger with Utah Power, and which have been added to service since then? 2. InterJurisdictional Cost Allocation a. In each of the six states in which it operates, what interjurisdictional cost allocation method does PacifiCorp use to allocate costs and revenues associated with PacifiCorp’s generation, transmission, distribution system, and administrative functions in retail rates? a.i. What is the status of other state regulatory commissions’ adoption of PacifiCorp’s Revised Protocol, including specific modifications that commissions have required? b. Does PacifiCorp’s Revised Protocol shift the cost burden of Eastern control area resources to customers in California without a commensurate sharing of benefits to California customers? b.i. Are California ratepayers paying a larger share of PacifiCorp’s systemwide costs than what is reasonable? c. Would the Washington UTC’s WCA interjurisdictional cost allocation methodology result in electric rates for PacifiCorp customers in California that are more just and reasonable than electric rates based on PacifiCorp’s Revised Protocol? d. What generation and transmission investments or divestments has PacifiCorp made (or initiated) since its 2011 GRC? e. What are the potential cost impacts to California customers of Oregon law requiring accelerated depreciation of PacifiCorp’s coal assets?

12 f. Identify, characterize, and evaluate how PacifiCorp uses and apportions costs and revenues for generation resources that it characterizes in its Revised Protocol as: f.i. System resources (resources that are not seasonal, regional or state resources) f.ii. Regional resources (e.g. WCA hydroelectric facilities, midColumbia contracts, and contracts to replace midColumbia contracts) f.iii. Seasonal resources (e.g. simplecycle combustion turbines, seasonal contracts, Cholla Unit IV and the Arizona Public Service exchange f.iv. State resources (e.g. demandside management programs, portfolio standards, and qualifying facility contracts) f.iv.1. Why does PacifiCorp treat qualifying facility contracts similarly to “regional resources?” f.v. Administrative and general costs g. What PacifiCorp corporate structural alternatives or cost allocation alternatives may result in just and reasonable rates in California? 3. Audit of EPS Compliance a. Do other state jurisdictions require PacifiCorp to review and report on the potential impacts of different carbon policies in its Integrated Resource Planning process, and if so, how? b. Do other state jurisdictions require PacifiCorp to disclose its GHG emissions or expected change in overall emissions as a result of changes to its portfolio, including new capacity additions? c. Have other state jurisdictions adopted rules specifically regulating PacifiCorp’s emissions of greenhouse gases from electricity generating facilities? d. If PacifiCorp’s system emissions factor exceeds the 1,100 pounds of

CO2 per MWh emissions limit of the EPS, is it reasonable to continue to allow PacifiCorp to demonstrate alternative compliance with the EPS? e. What are the emissions impacts of Oregon law requiring accelerated depreciation of PacifiCorp’s coal assets? f. What coal and other thermal resources owned or under contract by PacifiCorp serve California load? For each such thermal resource: f.i. What was the annual greenhouse gas emission factor and capacity factor for the period since PacifiCorp’s last GRC? f.ii. What is the current contract term, and when was the contract term last amended? f.iii. What is the remaining useful life of utility owned generation?

13 f.iv. Since the Commission adopted D.0701039, has PacifiCorp made any new longterm financial commitments with baseload generators that have emissions in excess of 1,100 pounds of CO2 per MWh? g. What thermal resources with emissions that exceed the EPS emissions intensity do not serve California load but have costs that are allocated to California retail customers?

2.2. Issues Out of Scope This investigation is intended to inform future ratemaking proceedings that evaluate PacifiCorp’s revenue requirements, practices, service, facilities, and maintenance practices for the purposes of setting rates; however, it will not set rates. In D.1609046, the Commission required PacifiCorp to file a 2019 Test Year GRC for rates effective January 1, 2019. We will consider that filing as a separate proceeding from this investigation, and the Commission can decide at a later date whether to consolidate this investigation with PacifiCorp’s 2019 Test Year GRC once it is filed. Accordingly, the following issues are outside the scope of this proceeding: 1. PacifiCorp’s 2019 test year revenue requirement. 2. Allocation of revenue requirements to rate schedule classes.

2.3. Schedule The preliminary schedule is set forth below.27 A final schedule will be adopted in the Assigned Commissioner’s Scoping Memo in this case. The schedule may be modified by written ruling by the assigned Administrative Law Judge (ALJ) or the assigned Commissioner.

Item Date Responses to the OII Thirty days after adoption by the Commission Prehearing Conference Within 30 days of receipt of responses Scoping Memo Within 30 days of prehearing conference Prepared Testimony ~Four Weeks after Scoping Memo Prepared Rebuttal Testimony ~Four Weeks after Prepared Testimony Hearings (if needed) ~Two Weeks after Rebuttal Testimony Opening Briefs ~Three Weeks after Evidentiary Hearings Reply Briefs ~Two Weeks after Opening Briefs Proposed Decision ~90 days after Submission Final Decision ~30 days from Proposed Decision

27 The schedule is preliminary and subject to change. 14 Pursuant to the authorization conferred by Pub. Util. Code § 1701.5(b), this proceeding may extend for 24 months beyond the date of this Order Instituting Investigation (OII). The OII presents many complex issues and may involve multiple parties. Therefore it is reasonable to adopt a 24month timeframe for this proceeding.

3. Responses to the OII and Party Status PacifiCorp (U901E), an Oregon Company at 825 N.E. Multnomah Street, Suite 1800, Portland, OR 97232, is a respondent to this OII. Other entities interested in participating in this OII may file a response to the preliminary scope, schedule and need for hearing determination within 30 days of adoption of this OII by the Commission. Entities that file responses will be granted party status.

4. Category and Ex Parte Communications The proceeding is categorized as ratesetting. Pursuant to Rule 7.1(c); this determination is appealable under the procedures in Rule 7.6. Ex parte communications are governed by Pub. Util. Code § 1701.1 et seq. and Article 8 of the Commission’s Rules of Practice and Procedure. Communication with the assigned ALJ shall occur either through formal filing or via written email to the entire service list of this proceeding.

5. Need for Hearings Pursuant to Rule 7.1(c), it is preliminarily determined that hearings will be needed in this proceeding. A final determination on the need for hearings will be made in the assigned Commissioner’s Scoping Memo.

6. Notice and Distribution of OII In the interest of broad notice, this OII will be served on the official service lists for the following dockets: Application 0911015, In the Matter of the Application of PacifiCorp (U901E) an Oregon Company, for an Order Authorizing a General Rate Increase Effective January 1, 2011. Application 1003015, In the Matter of the Application of PacifiCorp (U901E), an Oregon Company, for an Order Authorizing a Rate Increase Effective January 1, 2011 and Granting Conditional Authorization to Transfer Assets, pursuant to the Klamath Hydroelectric Settlement Agreement.

15 Application 1502013, In the Matter of the Application of PacifiCorp (U901E) for Approval of the California Alternate Rates for Energy and Energy Savings Assistance Programs and Budgets for Program Years 2015 2017. Application 1507005, In the Matter of the Application of PacifiCorp (U901E) Setting Forth its Distribution Resource Plan Pursuant to Public Utilities Code Section 769. Application 1509007, In the Matter of the Application of PACIFICORP (U901E) for Authority to Sell Certain Mining Assets in Accordance with Public Utilities Code Section 851. Application 1511005, Application of PACIFICORP (U901E), an Oregon Company, for a Permit to Construct the Lassen Substation Project Pursuant to General Order 131D. Application 1608001, In the Matter of the Application of PacifiCorp (U901E) for Approval of its 2017 Energy Cost Adjustment Clause and Greenhouse GasRelated Forecast and Reconciliation of Costs and Revenue. Service of this OII does not confer party status or place a person or organization that has received such service on the Official Service List for this proceeding, except as otherwise noted (PacifiCorp as respondent is automatically a party; entities that file responses to the OII will be conferred party status). To be placed on the service list, persons or entities should follow the instructions in Section 7, below.

7. Addition to the Official Service List Additions to the official service list shall be governed by Rule 1.9(f). Persons who file responsive comments to the OII will become parties to this proceeding and will be added to the “Parties” category of the official service list upon such filing. In order to assure service of comments and other documents and correspondence in advance of obtaining party status, persons should promptly request addition to the “Information Only” category as described below. They will be removed from that category upon obtaining party status. Any person will be added to the “Information Only” category of the official service list upon request and will receive electronic service of all documents in the proceeding. Interested entities should request to be added to the service list promptly to ensure timely service of comments and other documents and correspondence in the proceeding. (See Rule1.9(f).) The request must be sent to the Process Office by email

16 ([email protected]) or letter (Process Office, California Public Utilities Commission, 505 Van Ness Avenue, San Francisco, California 94102). Please include the Docket number of this investigation in the request.

8. Subscription Service Persons may monitor the proceeding by subscribing to receive electronic copies of documents in this proceeding that are published on the Commission’s website. There is no need to be on the official service list in order to use the subscription service. Instructions for enrolling in the subscription service are available on the Commission’s website at http://subscribecpuc.cpuc.ca.gov/.

9. Filing and Service of Comments and Other Documents Filing and service of comments and other documents in this proceeding are governed by the rules contained in article 1 of the Commission’s Rules of Practice and Procedure. (See particularly Rules 1.5 through 1.10 and 1.13). If you have questions about the Commission’s filing and service procedures, contact the Docket Office ([email protected]) or check the Practitioner’s Page on our website at www.cpuc.ca.gov.

10. Public Advisor Any person or entity interested in participating in this Rulemaking who is unfamiliar with the Commission’s procedures should contact the Commission’s Public Advisor in San Francisco at (415) 7032074 or (866) 8498390 or email [email protected]. The TYY number is (866) 8367825.

11. Intervenor Compensation Any party that expects to claim intervenor compensation for its participation in this Investigation must file its notice of intent to claim intervenor compensation within 30 days of the filing of a response to the OII, except that notice may also be filed within 30 days of the prehearing conference. Intervenor compensation rules are governed by § 1801 et seq. of the Public Utilities Code. Parties new to participating in Commission proceedings may contact the Public Advisor’s office for assistance. Contact information is set forth in Section 11, above.

17 IT IS ORDERED that: 1. The Commission institutes this investigation on its own motion to: 1) examine generation and transmission resources in PacifiCorp’s Western and Eastern control areas to determine whether PacifiCorp engages in leastcost planning and dispatch on a systemwide or control area basis; 2) determine whether PacifiCorp’s InterJurisdictional Cost Allocation Protocol results in just and reasonable rates in California; and 3) evaluate PacifiCorp’s compliance with the Emissions Performance Standard. The preliminary scope and schedule are set forth herein. 2. PacifiCorp (U901E), an Oregon Company at 825 N.E. Multnomah Street, Suite 1800, Portland, OR, 97232, is named as a respondent to this investigation. 3. Responses to the preliminary scope, schedule and determination on the need for hearings are due 30 days after the Commission adopts this Order Instituting Investigation. 4. Any entity that submits a response or reply will be conferred party status in this proceeding. 5. This Order Instituting Investigation is classified as ratesetting. Pursuant to Rule 7.1(c) of the Commission’s Rules of Practice and Procedure, this determination is final but appealable under the procedures in Rule 7.6. 6. This Order Instituting Investigation preliminarily determines that hearings will be needed. 7. The Executive Director shall cause this Order Instituting Investigation to be served on the following service lists: Application 0911015, In the Matter of the Application of PacifiCorp (U901E) an Oregon Company, for an Order Authorizing a General Rate Increase Effective January 1, 2011. Application 1003015, In the Matter of the Application of PacifiCorp (U901E), an Oregon Company, for an Order Authorizing a Rate Increase Effective January 1, 2011 and Granting Conditional Authorization to Transfer Assets, pursuant to the Klamath Hydroelectric Settlement Agreement. Application 1502001 et al., In the Matter of the Application of Southwest Gas Corporation (U905G) for Approval of Low-Income Programs and Budgets for Program Years 2015-2017.

18 Application 1507005 et al., In the Matter of the Application of PacifiCorp (U901E) Setting Forth its Distribution Resource Plan Pursuant to Public Utilities Code Section 769. Application 1509007, In the Matter of the Application of PACIFICORP (U901E) for Authority to Sell Certain Mining Assets in Accordance with Public Utilities Code Section 851. Application 1511005, Application of PACIFICORP (U901E), an Oregon Company, for a Permit to Construct the Lassen Substation Project Pursuant to General Order 131D. Application 1608001, In the Matter of the Application of PacifiCorp (U901E) for Approval of its 2017 Energy Cost Adjustment Clause and Greenhouse GasRelated Forecast and Reconciliation of Costs and Revenue. 8. Ex Parte communications in this investigation are governed by Public Utilities Code Section 1701.1 et seq. and Article 8 of the Commission’s Rules of Practice and Procedure. Communications with the assigned Administrative Law Judge shall occur either through formal filing or via email written to the entire service list in this proceeding. 9. The assigned Administrative Law Judge (ALJ) shall set a Prehearing Conference and if needed, Public Participation Hearings, in this proceeding as soon as practicable after the receipt of responses to the Order Instituting Investigation. The assigned Commissioner or ALJ may adjust the schedule or scope identified herein as needed to promote the efficient and fair resolution of this investigation. 10. A party that expects to request intervenor compensation for its participation in this proceeding must file its notice of intent to claim intervenor compensation within 30 days of the filing of a response, except that notice may be filed within 30 days of a prehearing conference in the event that one is held. (See Rule 17.1(a)(2) of the Commission’s Rules of Practice and Procedure.) This order is effective today. Dated April 27, 2017, at San Francisco, California.

MICHAEL PICKER President CARLA J. PETERMAN LIANE M. RANDOLPH 19 MARTHA GUZMAN ACEVES CLIFFORD RECHTSCHAFFEN Commissioners

20 ATTACHMENT 1 I.17-04-019 ALJ/GK1/jt2

PacifiCorp’s Retail Service Territories as of December 31, 201428

28 PacifiCorp 2014 Form 10-K Annual Report to the Securities and Exchange Commission at 8.