20231106PAC to Staff 1-10.pdf

1407 W North Temple, Suite 330 Salt Lake City, Utah 84116
November 6, 2023 Jan Noriyuki Idaho Public Utilities Commission 472 W. Washington
Boise, ID 83702-5918 [e-mail] (C) RE: ID PAC-E-23-20
IPUC Set 1 (1-10) Please find enclosed Rocky Mountain Power’s Responses to IPUC 1st Set Data Requests 1-10. If you have any questions, please feel free to call me at [phone].
Sincerely, ____/s/____ Mark Alder Manager, Regulation Enclosures

RECEIVED
Monday, November 6, 2023 2:37:30 PM
IDAHO PUBLIC
UTILITIES COMMISSION
PAC-E-23-20 / Rocky Mountain Power November 6, 2023 IPUC Data Request 1
IPUC Data Request 1 Please explain why sales to wholesale customers under tariffs set by the Federal Energy Regulatory Commission (FERC) are zero starting in year 2028.
Response to IPUC Data Request 1 All customers are expected to stop taking wholesale service under Federal Energy
Regulatory Commission (FERC) tariffs by July 1, 2027.
Recordholder: Lee Elder Sponsor: Lee Elder
PAC-E-23-20 / Rocky Mountain Power November 6, 2023 IPUC Data Request 2
IPUC Data Request 2 Figure 1 below compares the 2022 system load forecast and the 2023 system load forecast.

Please respond to the following: (a) Please explain why the 2023 load forecast is lower than the 2022 load forecast from 2023 through 2027. (b) Please explain why the 2023 load forecast is higher than the 2022 load forecast from
2028 through 2039.
(c) Please explain why the 2023 load forecast is lower than the 2022 load forecast from 2040 through 2041. Response to IPUC Data Request 2
The Company clarifies that “Figure 1” in this data request was created by Idaho Public Utilities Commission (IPUC) staff which the Company assumes was derived from the data contained in Appendix A to the Company’s Application in this proceeding.

(a) The 2023 load forecast is lower than the 2022 load forecast from 2023 through 2027 due to schedule delays in projects for commercial and industrial customers primarily in Utah and Oregon. (b) The 2023 load forecast is higher than the 2022 load forecast from 2028 through 2039
due to planned load increases for new and existing commercial and industrial
customers primarily in Utah and Oregon. (c) The 2023 load forecast is lower than the 2022 load forecast in 2040 and 2041 due to
increased energy efficiency (EE) expectations and increased private generation (PG)
expectations driven by the Inflation Reduction Act of 2022 (IRA).
PAC-E-23-20 / Rocky Mountain Power November 6, 2023 IPUC Data Request 2
Recordholder: Lee Elder Sponsor: Lee Elder
PAC-E-23-20 / Rocky Mountain Power November 6, 2023 IPUC Data Request 3
IPUC Data Request 3 Figure 2 below compares the 2022 load forecast and the 2023 load forecast in Idaho.

Please respond to the following:
(a) Please explain and provide evidence for why the 2023 load forecast is lower than the 2022 load forecast. (b) Please explain and provide evidence for why the trend of the 2023 load forecast declines while the trend of the 2022 load forecast shows growth. Response to IPUC Data Request 3
The Company clarifies that “Figure 2” in this data request was created by Idaho
Public Utilities Commission (IPUC) staff which the Company assumes was derived from the data contained in Appendix A to the Company’s Application in this proceeding. (a) The 2023 load forecast is lower than the 2022 load forecast primarily due to lower expectation for a large customer, increased energy efficiency (EE) and increased private generation (PG) expectations driven by the Inflation Reduction Act of 2022 (IRA).
(b) The trend of the 2023 load forecast declines while the trend of the 2022 load
forecast shows growth due to the impact of increased EE expectations and increased PG expectations driven by IRA. Recordholder: Lee Elder Sponsor: Lee Elder
PAC-E-23-20 / Rocky Mountain Power November 6, 2023 IPUC Data Request 4
IPUC Data Request 4 Please identify the software(s) the Company uses to calculate Integrated Resource Plan (IRP) based avoided cost of energy and avoided cost of capacity,
respectively, used to determine IRP-based avoided cost rates. Also, for the model
that determines avoided cost of energy, please confirm that the model dispatches resources to meet the system load.
Response to IPUC Data Request 4
The Company currently calculates Integrated Resource Plan (IRP) based avoided cost of energy using the Generation and Regulation Initiative Decision Tools model (GRID). This model is setup to calculate the highest displaceable incremental cost, i.e. it does not allow the proposed qualifying facility (QF)
resource addition to contribute to incremental wholesale energy sales. This has the
effect of ensuring the QF contributes to dispatch to meet system load. Following the acknowledgment of the 2023 IRP, the Company intends to transition the avoided cost of energy calculation to the PLEXOS model, which is used to
develop the IRP.
The avoided cost of capacity is calculated in a spreadsheet based on the cost of the avoided capacity resource and the capacity contribution of the QF resource.
Recordholder: Dan MacNeil
Sponsor: Dan MacNeil
PAC-E-23-20 / Rocky Mountain Power November 6, 2023 IPUC Data Request 5
IPUC Data Request 5 Please respond to the following regarding the Official Forward Price Curve (OFPC).

(a) Please explain the overall methodology and data sources the Company uses to determine the proposed OFPC.
(b) Please confirm that the methodology used in this case is the same as the
methodology used in Case No. PAC-E-22-16. If not the same, please explain the difference. (c) Please provide a detailed explanation how each hub's index is determined and whether each hub's index is derived from Henry Hub's index.

(d) Please explain how the monthly OFPC contained in Appendix A of the Application is aggregated into the proposed annual OFPC.
Response to IPUC Data Request 5
(a) The first 36 months of PacifiCorp’s official forward price curve (OFPC) are composed of the average of broker quotes for primary power and natural gas hubs. This 36-month period is referred to as the “market period”. Secondary prices use a basis estimate to the most relevant primary curve in the market
period.
Months 37 through 48 are a blend of market prices in months 25-36 (explained above) and fundamentals prices in months 49-60 (explained
below). The 37 through 48-month period is referred to as the “blending
period”. Months 49 and beyond of the OFPC, referred to as the “fundamentals period”, are provided to PacifiCorp on a quarterly basis by a consultant, Siemens Power Technologies International (Siemens PTI). Siemens PTI develops the
natural gas price forecast and a long-term resource expansion plan for the
Western Interconnect, and then provides a monthly heavy load hour (HLH) / light load hour (LLH) electricity price forecast for various market points, as well as monthly natural gas prices for various natural gas locations. (b) Confirmed. Market, blending, and fundamentals period methodologies are the same period methodologies in the Company’s OFPC utilized in Case No. PAC-E-22-16 (PacifiCorp’s Application to Update Load and Gas Forecasts Used in the IRP Avoided Cost Model filed in October 2022).
PAC-E-23-20 / Rocky Mountain Power November 6, 2023 IPUC Data Request 5
(c) Referencing the data contained in Appendix A to the Company’s Application in this proceeding, the Company responds as follows: The hubs shown are all primary locations for which the Company uses broker
quotes in the market period and Siemens PTI forecasts in the fundamentals
period. Siemens PTI’s natural gas price forecasts are based on regional supply and demand and transportation capability, rather than basis differentials. For less liquid market points, the Company uses a basis differential to a nearby
market point, rather than to Henry Hub. Please refer to the Company’s
response to subpart (a) above. (d) Referencing the data contained in Appendix A to the Company’s Application in this proceeding, the Company responds as follows:
The annual values shown were calculated using a simple average of the
monthly values that make up the underlying OFPC.
Recordholder: Dan MacNeil / David Rubenstein
Sponsor: Dan MacNeil / David Rubenstein
PAC-E-23-20 / Rocky Mountain Power November 6, 2023 IPUC Data Request 6
IPUC Data Request 6 Figure 3 below compares the 2022 HenryHub forecast and the 2023 HenryHub forecast. Please explain why the 2023 HenryHub forecast is lower than the 2022
HenryHub forecast.

Response to IPUC Data Request 6
The Company clarifies that “Figure 3” in this data request was created by Idaho Public Utilities Commission (IPUC) staff which the Company assumes was derived from the data contained in Appendix A to the Company’s Application in this proceeding.
Changes in the first 36 months of the 2022 forecast are a result of market changes observed through broker quotes. Prices in the fundamentals period, starting in month 49, have recently fallen as a result of a forecasted decrease in liquified natural gas (LNG) demand. Prices rise over time as future supply is expected to be at higher costs of production, though this is tempered by failing residential
demand as a result of building electrification. Recordholder: Dan MacNeil
Sponsor: Dan MacNeil
PAC-E-23-20 / Rocky Mountain Power November 6, 2023 IPUC Data Request 7
IPUC Data Request 7 Figure 4 below compares the 2022 Sumas forecast and the 2023 Sumas forecast. Please explain why the 2023 Sumas forecast is higher than the 2022 Sumas
forecast, contradicting the Henry Hub's trend.

Response to IPUC Data Request 7

The Company clarifies that “Figure 4” in this data request was created by Idaho Public Utilities Commission (IPUC) staff which the Company assumes was derived from the data contained in Appendix A to the Company’s Application in
this proceeding.
Changes in the first 36 months of the 2022 forecast are a result of market changes observed through broker quotes. The Company has not specifically identified the basis for the referenced changes in the fundamentals period starting in month 49 as the values are provided by its consultant, Siemens PTI. In general, the Siemens
PTI results reflect impacts on both supply and demand. Because pipeline
capability is limited, the western United States (U.S.) is relatively insulated from natural gas prices at Henry Hub, so changes tend to reflect regional supply and demand.
Recordholder: Dan MacNeil Sponsor: Dan MacNeil
PAC-E-23-20 / Rocky Mountain Power November 6, 2023 IPUC Data Request 8
IPUC Data Request 8 Figure 5 compares the HenryHub forecast and the Sumas forecast proposed in this case. Please explain why the HenryHub forecast is consistently lower than the
Sumas forecast.

Response to IPUC Data Request 8 The Company clarifies that “Figure 5” in this data request was created by Idaho Public Utilities Commission (IPUC) staff which the Company assumes was derived from the data contained in Appendix A to the Company’s Application in this proceeding. Henry Hub is the primary natural gas trading hub in the United States (U.S.) and
is located relatively close to major natural gas production, transportation and storage facilities. Sumas serves as the primary trading hub for gas consumed in, or passing through, the Pacific Northwest. Sumas does not have the same proximity to natural gas infrastructure leading to generally higher prices. Recordholder: David Rubenstein Sponsor: David Rubenstein

PAC-E-23-20 / Rocky Mountain Power November 6, 2023 IPUC Data Request 9
IPUC Data Request 9 Page 2 of the Application states that if approved, the load forecast natural gas forecast, and contract information will be incorporated into the Company's IRP
avoided cost model. However, Page 6 of the Application states that new contracts,
terminated or expired contracts, as well as new contract pricing are all updated in the IRP model on a continuous basis. Please reconcile the two practices and explain which practice the Company conducts.
Response to IPUC Data Request 9 The Company incorporates new contracts, and terminated or expired contracts on a continuous basis as part of its Public Utility Regulatory Policies Act (PURPA) queue. Order No. 33357 allowed “utilities to update their incremental pricing for
QFs in their PURPA queue”. The pricing for a specific PURPA request includes
signed contracts as well as prior queued QF requests for indicative pricing. The queue is managed in accordance with the Qualifying Facility Avoided Cost Procedures contained in Schedule 38, available online at:

https://www.rockymountainpower.net/content/dam/pcorp/documents/en/rockymountainpower/rates-regulation/idaho/rates/038_Qualifying_Facility_Avoided_Cost_Procedures.pdf
Recordholder: Dan MacNeil
Sponsor: Dan MacNeil
PAC-E-23-20 / Rocky Mountain Power November 6, 2023 IPUC Data Request 10
IPUC Data Request 10 Table 3 on Page 7 of the Application lists “OR CSP QF PPA” projects and "QF PPA" projects. Please explain the difference between the two types of projects.
Response to IPUC Data Request 10 The Oregon Community Solar Program (CSP) allows customers to subscribe to a
community solar project, which may be up to 3 megawatts (MW) in size. There
are differences in the price paid to the community solar project, depending on whether their output is fully subscribed, but from the perspective of system dispatch or load and resource balance, the Company treats them like any other qualifying facility (QF).
Details on the Oregon CSP are publicly available and can be accessed by utilizing
the following website link: https://www.pacificpower.net/savings-energy-choices/blue-sky-renewable-
energy/oregon-community-solar.html
Recordholder: Dan MacNeil Sponsor: Dan MacNeil