Clause 51 BBI allocations: NZGP 1.1 CNI Allocation Tiwai Stays re-run

Generated: 2026-01-27 14:10:47.190688, sddp2tpm version: 1.17.0, User: davisc

Allocations

Working tables

Wind repowering adjustments for generator PVEMBD

According to the TPM¹, benefits due to large steps in future generation should not be included when determining starting allocations. Plants not already committed are already excluded in the input plants.csv. However, several existing wind farms are assumed to undergo repowering at set times in the future. While it is reasonable to include future benefits due to the current capacity of these plants, we should not include future increases to capacity of these wind farms.

In SDDP wind farm repowering is handled by replacing the existing wind farm with a new plant with increased capacity. To exclude benefits do to increases in capacity, generator PVEMBD for repowered plants is multiplied by the ratio of the original capacity to the repowered capacity.

Output file: repower_adj.csv

Clause 51 periods of benefit

The table below indicates the AC and DC binding conditions for which load customer groups benefit from the investment via alleviated prices. The rules for these periods are described in paras. 353 - 356 of the Assumptions Book⁴.

The following table shows the actual difference in the present value of time weighted average price between the factual and counterfactual during the periods of benefit defined above. Ideally the lowest values (the largest price decreases) should broadly correspond with green "+" cells in the table above. Similarly the largest price increases should correspond to red "-" cells above. The signs of the smaller values in the table below may not correspond to the load benefit periods above due to different hydro generation time series in the factual and counterfactual.

Step load adjustments for consumer PVEMBD

According to the TPM¹, benefits due to large steps in future demand should not be included when determining allocations.

At each bus with identified step loads we multiply load benefits by:

$$\textrm{step load adjustment} = 1 - \frac{\textrm{PV step loads}}{\textrm{PV total loads}}$$ , where PV indicates the present value of these loads summed over the BBI investment period. Step loads for each market scenario are provided in the input file sddp2tpm_data/data/step_loads.csv, and the total load comes from the demxba SDDP output.

The step load adjustments below are applied to the bus_constraint_pv.csv and bus_delta_pv.csv outputs from clause51 postprocessing.

Step load adjustment factor

Output file: step_load_adj.csv

Reallocation of load growth to EDBs at multi-customer nodes

Where there is more than one customer at a node, we attribute the load portion of PVEMBD to each customer based on their offtake intra-regional allocator (IRA) as a proportion of the total of all customers' offtake IRAs at that connection location.
Where some customers are non-distribution customer and others are electricity distribution businesses (EDB), we assume that the load growth at that connection location is wholly attributable to distributor customers, consistent with our demand forecasts for non-distributor customers, which generally assume no load growth.

The following table shows the nodes with multiple customers that include both EDB and non EDB customers, and the reallocation of load growth to EDBs at these nodes.

For non-EDB customers: $$alloc_{non-EDB} = \frac{w_{IRA}(PVdemand - PV\Delta demand)}{PVdemand}$$ For EDBs: $$alloc_{EDB} = alloc_{non-EDB} + \frac{w_{EDB}PV\Delta demand}{PVdemand}$$ , where $w_{IRA}$ (ira_weight) is the customer's IRA offtake divided by the total offtake at that location, and $w_{EDB}$ (edb_weight) is the EDB's offtake divided by the total EDB offtake at that location.

Nodes affected by this calculation are identified in the input sddp2tpm_data/data/multi_cust_nodes.csv.
The IRA offtakes for each customer/location are from the input sddp2tpm_data/data/ira.csv, and the demand and its growth are determined from the annual demand (averaged over hydro scenarios and weighted over market scenarios), which is in the clause51 output bus_annual.pv.

Because demand growth depends on the market scenario, load reallocation is also EDGS dependant.

The alloc column below scales the bus_constraint_pv.csv and bus_annual_delta_pv.csv load_supplied data, after summing over the buses for each location.

Output file: load_reallocation.csv

Regional Customer Groups

This topic is covered by Clause 50 of the TPM.

Regional customer groups (RCG) are obtained by:

1. seperating the customer connections into the modelled regions. The modelled regions are groups of substations that are seperated by transmission constraints being alleviated by the grid investment and the HVDC link.

2. classifying the customer connections in these regions as "supply" or "demand" depending on the absolute value of the generation and load PVEMBDs for that customer connection

3. Separating the demand and supply customer connections into the regional customer groups based on the type of load or generation. This supports the goal of providing customer allocations that are broadly proportionate to positive net private benefit (NPB)³. With this in mind we create "load_with_gen" and "gen_with_load" RCGs for customer connections that have comparable load and generation benefits².

RCGs and their NPBs for this investment

Output file: all_groups.csv

Clause 47 of the TPM states that to be considered a beneficiary (and hence have a cost allocation) for a BBI, they must belong to a RCG that has positive PVEMBD (NPB).

Benefitting customers and locations

The following table shows the customers and locations that belong to the benefitting RCGs abvove.
The output file customers.csv shows the corresponding table for all customer locations before filtering to beneficiaries.

The load_benefit column is obtained from the step-load adjusted consumer PVEMBD by

• applying the load reallocations above where applicable, and the IRA offtake ratio elsewhere to the PV of load supplied for the different periods of binding constraints and the change in load supplied (F - CF), all combined using the input load_benefit_periods.csv, as per the "Calculate EMBD for each market scenario - clause 51" section of the Assumptions Book⁴.

• taking the weighted sum of EDGS scenarios.

See the output file: big_load_table.csv for these intermediate values.

The gen_benefit column is obtained by

• applying the wind repowering adjustments to the the PV of generated energy for the different periods of binding constraints and the change in energy generated (F - CF), all combined using the input load_benefit_periods.csv, as per the "Calculate EMBD for each market scenario - clause 51" section of the Assumptions Book⁴.

• taking the weighted sum of EDGS scenarios.

See the output file: custloc_gen.csv for these intermediate values.

Output file: bens.csv

Determining final regional customer groups (FRCG)

For each Regional supply/demand group (e.g. (NI, supply), (SI, demand)):

• the provisional customer groups (e.g. NI_wind, NI_peaker, ...) are sorted by the ratio of PVEMBD to IRA, both summed over the group, from highest to lowest.
• the first provisional group on the list (the one with the highest PVEMBD/IRA) starts the first FRCG.
• Working down through the list, if a provisional group has a ratio higher than 80% of the previous provisional group, then it joins the same FRCG.

Output file: ben_groups.csv

Inputs

Regions: regions_cni/final_region_buses.yaml

clause51 output directory: clause51_output_cni_2025-11-17_10-12-18_lfd_fix

sddp2tpm_data directory: sddp2tpm_data/data

Renewable projects (for wind repowering adjustments): renewProjects.csv

Weights: {'disruptive': 0.2, 'environmental': 0.2, 'global': 0.2, 'growth': 0.2, 'reference': 0.2}

Output directory: alloc51cni_20260127