R746-700-23. Additional Power Costs Information for a Forecasted Test Period to Be Filed by an Electrical Corporation

A. An electrical corporation that has included power costs in a forecasted test period shall also file with the Commission the following information or documents relating to its power cost projections with a general rate case application. An applicant will provide an index which identifies where in the application, testimony, exhibits, documents, information, data, etc. filed with the application the applicant has responded to and complied with these R746-700-23 rule requirements. The index may be presented in testimony, as a table embedded in testimony, as an exhibit to testimony, or in any other manner so long as it is clearly identified. Contemporaneously with the filing of an application, an electrical corporation shall provide the following information and documents to the parties specified in R746-700-1.E.3, unless the information or document is already included in or with the application.

B. All information should be provided or available electronically and, in the case of Excel spreadsheets, with all formulas intact including all hierarchy of linked spreadsheets. The term "PCM" herein refers to any power cost model used by the utility, or any subsequent enhancements to or replacements of the power cost model used in the utility's last prior general rate case. The term "workpapers" means the documents used to develop the inputs to the PCM. This may include such items such as contracts, emails, white papers, studies, utility computer programs, Excel spreadsheets, word process documents, pdf and text files, computer programs, or any other data or documents relied upon to support the cost details in the application. If the inputs used in the PCM were developed from a document, such as a contract, provide the contract with the PCM inputs highlighted.

C. Power Cost Modeling Data:

1. Workpapers that show the source, calculations and details supporting the testimony, other exhibits and all PCM input data. The workpapers will include, at a minimum, copies of the net power cost report in Excel and the net power cost model database.

2. Identification of the time periods (Reference Period) used to determine input items (e.g., outage rates) in the PCM which are based upon an examination, average, etc. of a multi-year period.

3. Compilations of actual net power costs produced by the utility that were referenced in the testimony or exhibits, to the extent that actual power cost results are discussed or cited in the utility's testimony or exhibits.

4. A list and explanation of all modeling or logic changes or enhancements to the PCM that have been implemented since the last prior general rate case. This will include a statement of the direction and amount of change in net power costs resulting from each such change and documentation describing each Material change as well as PCM runs and workpapers quantifying the impacts of these changes.

5. Access to or a copy of the PCM model used by the utility to compute power costs in the Test Period.

6. The latest documentation for the PCM.

7. The current topology maps in the PCM along with an explanation for all the differences that have been made to the topology since the last prior general rate case and an explanation of why the changes were made. Include supporting documentation, such as contracts resulting in changes to the transfer capabilities used in the PCM.

8. All documents, workpapers, data or other information used by the utility in determining, setting, or calculating any PCM input, constraint, etc., including, but not limited to, where applicable:

a. market caps,

b. outage rates (planned and unplanned) including all backup data showing each outage (planned or unplanned, etc.) and duration (planned or unplanned) considered in the Reference Period, including NERC cause code, type of event, duration, energy lost, etc.,

c. the date and a copy of any forward price curve used, showing monthly heavy load hour and light load hour,

d. short-term firm transactions (including short-term firm indexed transactions and swaps), each transaction or contract will have a designation as to its purpose (i.e., trading, arbitrage or balancing.),

e. all contracts modeled in the PCM that were not included in or have been amended since the last prior general rate case, providing for each:

(i) A copy of the contract (in pdf or electronic format, if available), and

(ii) input assumptions related to the contract,

f. all fuel cost inputs,

g. heat rate curves for each resource, including the derivation of the heat rate curves,

h. identification of each instance in which the utility changed any maximum capacities, minimum up or down times or unit minimum capacities for thermal or hydro generators modeled in the PCM since the last prior general rate case,

i. each load adjustment,

j. inputs for Qualifying Facility or QF contracts,

k. screens applied to restrict uneconomic dispatch of resources,

l. start up fuel costs, start up O and M costs and any other form of start up costs modeled,

m. loss factor data used to develop the load forecast for the system and for each state for the most recent five calendar years and for the most recent five fiscal years; include a comparison of those loss factors to those that were used in developing loads for the PCM for the test period used in the case,

n. the system level loss factors assumed in any PCM used in the most recent (or current) rate cases for any other jurisdiction in which the utility operates,

o. the actual generation of each coal, gas, hydro and wind generating unit modeled in the PCM for each month for the Reference Period,

p. hourly generator logs for each wind, coal, gas and hydro unit modeled in the PCM for the Reference Period,

q. the schedule for each generation unit's planned and actual outages for the test period, the most recent calendar year and the next four calendar years,

r. hourly logs for all contracts modeled in the PCM, showing actual data (hourly sales or purchases) for the Reference Period,

s. the details of Short Term Firm and Non-Firm transmission used by the utlity during the Reference Period.

t. for each of the transmission contracts whose costs are included in the PCM, identify the purpose of the transaction, why it is used and useful in the test period, the amount of capacity or type of transmission service it provides, and where the capacity or service provided by this contract is modeled in the PCM,

u. data for the Reference Period or for the most recent four years available for all third party transmission imbalance transactions that have been included in Short Term Firm or secondary transactions during that period,

v. any links and other inputs for Short Term Firm (including any related to SP 15) and Non-Firm transmission modeling used in the PCM,

w. the hydro planned and unplanned outage rate,

x. to the extent that the utility uses any ramping adjustment in its case, information describing and detailing all ramping adjustments made (including all ramping energy assumed to be lost for each outage event modeled in the ramping analysis),

y. the costs of wind integration as modeled in the PCM, and

z. hedging contracts, already in place and those assumed for forecasting purposes.