20170815Utah_OCS Set 1 (1-62).docx

BEFORE THE PUBLIC SERVICE COMMISSION OF UTAHIn the Matter of the Voluntary Request:Docket No. 17-035-39Of Rocky Mountain Power for Approval:Office of Consumer ServicesOf Resource Decision to Repower:First Data Request toWind Facilities:Rocky Mountain Power:July 21, 2017Please provide responses to:BélaVastagPhilip HayetOffice of Consumer ServicesJ. Kennedy and Associates, Inc.160 East 300 South 570 Colonial Park Drive, Suite 305Salt Lake City, Utah 84111Roswell, GA 30075(801) 530-6374(770) [e-mail]@jkenn.com
Please provide copies of all past and future data requests and responses received by or sent from Rocky Mountain Power to any party in this docket. Please include both formal and informal responses.
General (IRP)
For each year over the last 20 years, provide one set of CO2 ($/Ton) forecasts (low, mod, high) that the Company used in the given year.
Please provide a copy of the PaR and System Optimizer User’s Manuals. If a signed copy of a confidentiality agreement is necessary, please expedite that process so that it may be taken care of.
The IRP process required Aurora to develop long-term wholesale power price forecast. Why doesn’t the Company use Aurora, or GRID, instead of SO and PaR for expansion planning and quantifying production costs? Please explain how the Company determines which models are appropriate for which analysis.
Please provide the SO and PaR inputs, outputs, and summary spreadsheets, electronically with all formulas intact, associated with the 2017 IRP preferred portfolio,
Please provide the latest GRID modeling files, including workpapers and GRID access, consistent with 2017 IRP assumptions. Please supply the Schedule 38 GRID database from June 21, 2017, if a more recent study is not available.
General (Repower)
Please provide copies of PacifiCorp’s responses to wind repowering data requests submitted by all parties in the states of Idaho, Washington, Oregon, Wyoming, and California in addition to those in Utah. This includes public and confidential data responses. Please provide the responses at, or shortly after, the time when the Company files its responses to other parties. As responses are provided, please include a summary of the state name, organization and DR#s for the DRs contained within each response.This is an ongoing request.
Please explain how the technology chosen for repowering compares to the technology under consideration for new sites considered in 17-035-40. Please explain if the technology available to repowering existing sites are limited compared to new sites. Please address any re-powering limitations such as sizing or technology limitations due to spacing between towers, tower specifications, foundation specifications, or other engineering considerations.
Has the Company ever had any experience with repowering a wind project. Please explain the Company’s prior experience.
Please provide all research, studies conducted or reviewed, memos, reports, or any other documents of any kind that the Company possesses regarding repowering wind projects.
Please explain what assumptions were required in the Aurora development of wholesale market prices and if the input assumptions were identical with those used in developing the SO and PaR models. If any assumptions were different, please compare the assumptions used in Aurora versus SO/PaR that were different.
Please provide a narrative explanation and supporting workpapers for how the Company modeled EIM and market depth/ market transactions for this docket in SO / PaR.
Explain whether the underlying SO and PaR databases used in this docket were identical to the databases used in the 17-035-40 docket. If any assumptions were different, please compare the assumptions that were different in each of the studies.
Hemstreet
Refer to lines 70 to 72 and lines 361 to 367 of Mr. Hemstreet’s testimony,
Please explain what analysis was conducted that led to the determination that it is now economic to repower Goodnoe Hills.
Please provide all cost-benefit analyses associated with the Goodnoe Hills repowering.
Please provide the historic budgeted and actual costs for blade failures and refurbishments over the last 10 years for the Company’s owned Wyoming wind projects, by facility.
Refer to lines 305 to 308 and lines 312 to 314 of Mr. Hemstreet’s testimony,
Does the Company currently have any long-term service agreements in place for maintenance of owned wind facilities?
Will the Company be contracting for Long Term Service Agreements for service of the repowered facilities?
Refer to lines 321 to 325 of Mr. Hemstreet’s testimony,
Have there been any pre-repowering generation decreases due to component failures at this time?
Are there any turbines that have already been idled in anticipation of repowering?
Explain how the pre-repowering generation impacts discussed at line 325 were factored into the Company’s repowering economic analysis.
At line 321, the Mr. Hemstreeet states that it would be more economic to idle the turbines than to repair given the short period before repowering. Will, in fact, an economic analysis be performed when a turbine failure occurs or has the Company already made the decision that it will not perform the necessary repair while it waits to repower the turbines?
Refer to lines 388 to 410 of Mr. Hemstreet’s testimony,
With respect to the additional features that improve reliability for the repowered facilities, will those features also be added to the new turbines contemplated in the 17-035-40 docket? Are these features unique to a single WTG or are these features added to a set of WTGs or the System as a whole? Please explain.
Please provide a technical explanation of how the two additional features work and improve reliability, and explain how the WindFREE Reactive Power feature can “often exceed - the performance of a conventional (non-wind) power plant.”
Please explain how even when wind turbines are not generating active power, they can provide reactive power.
See Hemstreet, beginning at line 410 “The provision of continued voltage support and regulation provides grid benefits not possible with conventional generation, while mitigating adverse voltage impacts of wind turbines being off-line due to wind conditions. This feature can eliminate the need for grid reinforcements specifically designed for no-wind conditions, and may allow for more economic commitment of other generating resources that will enhance grid security by reducing the risk of voltage collapse.”
Provide a technical explanation of what that sentence means.
Why can wind turbines provide grid benefits from the provision of continued voltage support and regulation that are not possible with conventional generation? Please explain.
How can wind turbines provide these benefits when the wind does not blow particularly given that the Company believes that wind turbines provide grid benefits that are not possible with conventional generation?
What grid reinforcements would have to be made that can be avoided by these enhancements that would be needed for the no-wind conditions?
See Hemstreet at line 431.
Explain how these features will improve transmission system reliability and compared to what?
Is this to suggest that the System would be operated less reliably without these new features, or that it would be more-costly to operate the System reliably without these new features? Can this benefit be quantified?
Please explain exactly how these new features would defer the need to add synchronous condensers or static VAr compensators, and under what conditions, at a later time, would the Company have to add these components?
What is the cost of these two new reliability features, and would the repowered turbines still be economically viable without the new features? Please explain.
Please provide the Company’s most recent wind integration cost study, and indicate if these new reliability features were accounted for in the development of the integration costs. If the reliability features were accounted for, please explain what was done, if not, please explain why not, and explain how the Company expects that the reliability features would affect the determination of the integration costs.
Refer to lines 496 to 504 of Mr. Hemstreet’s testimony
When does the Company expect to have a negotiated “a turn-key master retrofit contract with GE to perform the repowering”?
When does the Company expect to have negotiated “an installation contract with Vestas or with other qualified wind energy contractors”?
How did the company estimate the costs and model the economics of repowering without the final contracts negotiated for installation services?
Please refer to lines 546 to 551 of Hemstreet’s testimony, how did the Company determine the schedule and order for re-powering facilities? Please explain.
Please refer to TJH-3, page 1, columns F and I.
If the Company’s request to re-power is granted and work is completed as contemplated, what additional capacity will be acquired for reserve margin calculations? Please add to this table the capacity contribution used in the evaluation of reserve margin, both before repowering, and after.
Does the Company anticipate the capacity contribution for wind and/or LOLP to change based on new transmission capacity, advancements in wind technologies and reliability features” as discussed starting at Hemstreet line 388, or EIM benefits associated with efficient use of transmission? Please explain.
Please refer to TJH-3, page 2, columns D and E.
Please provide supporting workpapers or historic data used to derive the Current Long-Term Generation (MWh) in D12:D:29
Please provide supporting workpapers or engineering study documentation for the Turbine Generation Increase (%) values provided in E12:E29.
Please provide supporting workpapers or engineering study documentation for the Turbine Generation Increase (%) values provided in I12:I29.
As a general matter, for any column in TJH-3, either on page 1 or page 2, in which the Company has additional workpapers that have not already been provided, and that were used in the derivation of the data, such as the derivation of the Project In-Service Dates, please provide those additional workpapers, electronically, with all formulas intact.
Link
Please refer to Mr. Link’s testimony. Please provide a detailed reconciliation and a detailed cost breakdown (workpapers used in the derivations of the estimates) of the following costs:
Link testimony line 93: purchased safe-harbor equipment in Dec 2016 for $77.8 million
Link testimony line 341: upfront investment of $1.13 billion. For reconciliation purposes, is the $77.8 million part of the $1.13 billion?
RTL-1: capital costs in cells G25:G36 by facility. Please confirm that these values are consistent with the $1.13 billion at line 341 of Mr. Link’s testimony.
$52,640,700 referenced in the January 13, 2017 letter to the Commission. Again, is this part of the $1.113 billion?
Refer to lines 337 to 343 of Mr. Link’s testimony. Please provide a side by side comparison of the assumptions used in the re-powering analysis updated since the 2017 IRP.
Price-policy assumptions
up-front capital costs,
run-rate operating costs,
energy output for both the existing and repowered wind facilities.
Any other significant assumptions that changed between the two studies, including fuel costs, load forecast, etc.
Please explain how the Company stepped from the 2017 IRP preferred portfolio to the “repower” and base (no projects) cases provided in this docket. Please provide a listing of assumptions that varied between the 2017 IRP preferred portfolio and the “repowering” and “base (no projects)” cases provided in this docket.
Refer to line 352 of Mr. Link’s testimony.
Did the Company model the 36.5 MW reduction in transfer capacity in its IRP analysis? If not, why not?
Does the Company currently model this reduction in GRID? If not, why not?
Does the Company’s PaR analysis reflect an equivalent expected transfer capability? Does the PaR model perform iterations reflecting variability and potential unavailability of this transmission? If not, why not?
Refer to lines 382 to 389 of Mr. Link’s testimony. Please confirm that EIM benefits of more efficient use of transmission are accounted for in all cases studied, both under the scenarios with and without repowering, and provide a step by step explanation of the methodology that was used to incorporate modeling of EIM benefits.
Refer to line 196 of Mr. Link’s testimony. Did the System Optimizer select repowering as a resource alternative(s), or was the re-powering assumption for that case “locked in” and the model filled in resources around that decision to then compare to other cases? Please explain.
In this proceeding or the IRP, were the Repowering Resources ever set up as an Option that could be selected if economic as part of the System Optimizer runs? If so, please explain when, and how it was setup, and what the results were, and if not, please explain why this was never done.
For the input files provided in the SO Model Inputs-Outputs.zip and the PaR Inputs-Outputs.zip files that accompanied Mr. Link’s workpapers, there must have been spreadsheets that were created that analyzed information and created the model inputs. These spreadsheets would have been used to analyze information such as generating resource characteristics, fuel costs, capital costs, load data, transmission topology map and transfer capacities, CO2 emission rates, renewable resource characteristics, market data, transaction data, and any other data important to study performed. Please provide the supporting workpapers that were used to develop and format the input values.
Refer to lines 473 to 474 of Mr. Link’s testimony. Did the Company perform a retirement study to optimize the timing of Dave Johnston retirement? Please provide the Company’s analysis that determined 2027 as the retirement date, and all supporting workpapers, SO, PaR, spreadsheet, or otherwise regarding this determination.
Refer to lines 69-71, 466 – 467, and Table 1 of Mr. Link’s testimony.
How was the Company’s inflation rate assumption determined for PTC and the levelization calculations (revenue requirement, gas forecast in Table 1)? Please explain
Please provide all alternative inflation rate assumptions considered or reviewed during the 2017 IRP process or in conjunction with developing this filing. In other words, if there is an inflation rate associated with a gas forecast provided in Confidential Exhibit 2, please provide that inflation rate.
Please confirm that the inflation rate used for PTC, gas and CO2 forecasting, and revenue requirement levelization are consistent.
Refer to lines 488 - 490 of Mr. Link’s testimony, please provide a narrative explanation as to how the extension is computed. Please identify where this calculation was provided, or provide supplemental workpapers with formulas to derive these values.
Please provide the peak and energy load forecasts used in each S.O and PaR run studying repowering as well as the forecasts used in the preferred 2017 IRP portfolio.
Refer to the 2017 IRP page 309 (FS-REP final selection fact sheet). Please provide the workpapers and explanation for each of the system optimizer costs included in the Portfolio Summary Table, and explain if these costs are consistent with those used in modeling the cases used in this application. If they are not consistent, please provide this fact sheet for the application, and explain the differences. Please address the following specifically:
System cost without transmission upgrades ($22,907 m PVRR)
Transmission integration ($123 m PVRR)
Transmission reinforcement ($12 m PVRR)
Total cost ($23,042 m PVRR)
Total cost thru 2050 ($22,781 m PVRR)
Please refer to “RePower Data 20170516 LGIA Limit v13.xlsx”
Please provide historic O&M costs consistent with those forecasted on the “O&M” tab for all facilities on this page. Please provide historic data since in-service, and include every year of operation.
Please explain if the OMAG rows (16 and 33) are intended to be blank in the tabs of this file. Please explain if all OMAG costs are embedded in the Fixed OM rows (12 and 29). Please explain.
Does the Company believe annual OM expenses will be the same after re-powering as with the Status Quo? Please explain.
Larsen
Refer to line 286 - 289 of Mr. Larsen’s testimony. Please clarify if/ how the loss of PTC’s will be included in the EBA.
Refer to line 289 of Mr. Larsen’s testimony. Please explain if thereis any reason that would prevent the Company from filing a rate case, and if such a rate case could mitigate the impact of the current PTC’s ending.
Refer to lines 114 – 129 of Mr. Larsen’s testimony. Please quantify the costs, benefits, and net benefits that would flow to rate-payers and shareholders with and without RTM. Also for comparison purposes, please quantify the costs, benefits and net benefits that would flow to rate-payers and shareholders with and without rate-cases filed when the re-powering investment was completed and again when the new PTC’s expire.
With regard to JKL-3 and JKL-4, please provide a more detailed narrative explanation of how the rider works with regard to net power costs, and how the rider works in conjunction with the EBA proceeding. Also, with the understanding that the EBA does nothing more than true-up the actual costs that PacifiCorp incurred, and the actual revenues PacifiCorp received, why has the Company proposed to have a Net Power Cost Incremental Savings calculation as part of the RTM rider?
With regard to JKL-3confirm and clarify
Actual Net Power Costs are computed based on the annual costs and by definition would already account for reduced costs (benefits) due to wind-repowering, correct?
Is the Company suggesting that the EBA Actual NPC will be adjusted upward in the EBA Docket to a level that was expected without re-powering, so that the net power cost savings could be assigned and tracked through the RTM? It appears that this process could be burdensome, and why would it be desirable to go through this effort?
Aside from the inclusion of NPC benefits in the RTM, is the main result of implementing the RTM a cost recovery mechanism for the capital projects and the PTC impacts?
The company intends to “cap” the costs recovered through the RTM at a level equivalent to the derived savings, correct?
Will all Customers be subject to this RTM? Please provide detailed explanation as to which classes and special customers will or won’t be a part of this rate schedule.
Please explain if/how capping the RTM would imply the capped balance would be carried monthly at the annual simple interest rate of 6% that ratepayers would have to pay.
To accomplish the Company’s objective in introducing the RTM tariff, which is provided as JKL-5, wouldn’t there need to be a complimentary adjustment to the EBA tariff, Schedule 94? If so, why didn’t Mr. Larsen discuss that and provide the adjustment to Schedule 94, and if not, why not?
Contracts and PTC
Refer to the Direct Testimony of Mr. Hemstreet at page 6 at lines 122-133. Please provide copies of all contracts executed with General Electric International, Inc. and Vestas American Wind Technology, Inc. associated with the December 2016 equipment purchases for wind repowering.
Refer to the Direct Testimony of Mr. Hemstreet at page 6 at lines 122-133. Please provide copies of all purchase orders and invoices for equipment purchases from General Electric International, Inc. and Vestas American Wind Technology, Inc. applicable to the December 2016 safe-harbor equipment purchases for wind repowering.
Refer to the Direct Testimony of Mr. Link at page 5 at line 93. Please provide a listing of all equipment and amounts purchased from General Electric International, Inc. and Vestas American Wind Technology, Inc. for wind repowering that summed to the $77.8 million indicated by Mr. Link.
Refer to the Direct Testimony of Mr. Hemstreet at page 6 at lines 122-133. Please provide copies of all analyses or reports completed to justify that the 5% safe-harbor requirements are expected to be met by the December 2016 equipment purchases from General Electric International, Inc. and Vestas American Wind Technology, Inc. for the wind repowering. Please provide copies of all analyses in electronic format with all formulas intact.
Refer to the Direct Testimony of Mr. Hemstreet at page 6 at lines 122-133. Please describe the current status and location of the equipment purchased in December 2016 for the wind repowering. Be sure to indicate if the Company has taken possession of the equipment or whether it is being held by the vendors.
Please identify any other equipment purchases made or other costs incurred to date for the wind repowering that were not recorded in December 2016.
Please describe what would be done with the wind repowering equipment purchased from General Electric International, Inc. and Vestas American Wind Technology, Inc. in December 2016 if regulatory approvals for cost recovery are not granted and the repowering project does not proceed.
Please describe in detail the extent to which equipment purchased for the repowering project and for the new development wind powering project are expected to be interchangeable. For instance, if the repowering project is authorized and the new wind project is either not authorized or different vendors are chosen through the RFP process, describe whether the equipment already purchased for the new wind project could be utilized in the repowering project?
Refer to the Direct Testimony of Mr. Hemstreet at page 7 at lines 151-158. Please provide copies of all analyses or reports completed to ensure that the 80/20 test will be met for each turbine repowered. Please provide copies of all analyses in electronic format with all formulas intact.
Refer to the Direct Testimony of Mr. Hemstreet at page 7 at lines 139-150. Please describe the fair market values assumed for each component (foundation, tower, and machine head including nacelle, hub, and rotor) of the typical repowered wind-turbine-generator utilized in the Company’s assessments to ensure that the 80/20 test will be met for each turbine repowered and the source of those assumptions.
Please provide copies of all internal or external accounting or legal assessments, analyses, reports, or opinions available to the Company regarding the Company’s attainment of the 5% safe-harbor requirements or the 80/20 test requirements for the wind repowering.
Please provide citations to all IRS or other sourced guidance relied upon by the Company in regards to the 5% safe-harbor or 80/20 test requirements. If the Company is aware of any specific IRS Private Letter Rulings related to these decision criteria, please cite in the response.
Refer to the Direct Testimony of Mr. Hemstreet at page 7 at lines 142-148. Please describe how the Company plans to determine the fair market value of the remaining equipment to apply the provisions of the IRS’s 80/20 test on a “turbine-by-turbine” basis and when such an evaluation would take place.
Please describe the timing of the Company’s decision to engage in the purchase of the equipment necessary to meet the 5% safe-harbor requirements and whether the final determination was delayed until a specific IRS guidance was issued. If so, please cite that guidance. In addition, please state what in that guidance was a crucial decision-making factor(s) in the decision to proceed.
Please provide copies of all corporate board minutes related to the decision to move forward with the purchase of equipment necessary to meet the 5% safe-harbor requirements for the wind repowering.
Refer to the Company’s 2016 Form 1 at page 216 line 8 which details the CWIP in account 107 for “Wind Repowering/New Development/Safe Harbor Equipment Purchases” for $111,124,301. Please provide the amount of safe-harbor equipment purchased separately for the “Wind Repowering” and the “New Development” projects. If not purchased separately or disaggregated, please explain why.