Matter No. 529
NEW BRUNSWICK ENERGY AND UTILITIES BOARD
INTERROGATORY (Rule 4.2)
In Relation to an Application by: New Brunswick Power Corporation (“NB Power”)
In Accordance with: Section 103(1) of the Electricity Act, SNB 2013,
c.E-7, to the New Brunswick Energy and Utilities Board (the “Board”)
with respect to proposed changes to its rate structure, rates classes
and rate design.
TO: New Brunswick Power Corporation
FROM: J.D. Irving Limited (“JDI”)
NB Power (JDI)
IR-1
March 23, 2023
Reference:
In response to JDI Round 1 IR-20i, NBP provided CCAS models for
monthly and seasonal cost allocation alternatives. These questions
specifically reference Exhibit NBP 07.14, NBP Response to JDI IR-20gi
– Attachment on the ‘CCAS Seasonal Monthly Model’ and Exhibit NBP
07.16 NDP Response to JDI IR-20i iii Attachment CCAS Seasonal
‘Alternative 1’ which provides seasonal allocation for the variable
costs (specifically fuel costs).
Similar scenarios were described in an Elenchus report filed in Matter
357, Exhibit NBP 2.03. Page 9 of that report in explanation of the
seasonal allocation of variable costs only scenario explains:
As a sensitivity, Elenchus has considered the option of applying
seasonality to only the variable costs. NB Power affirms that
amortization costs, plant capital costs, and most plant OM&A are
indeed fixed costs which do not vary by production. The costs which
differ by season are indeed the fuel, and imports (net of exports).
Therefore, for this sensitivity, only the fuel and imported energy
(net of exports) is considered for seasonality.
This question also references NBP Exhibit 1.20 as a comparison, which
is the proposed CCAS model for the same 2020-2021 Fiscal year as
provided in the referenced models above.
JDI is analysing cost drivers to help determine appropriate class
categorization and rate design priorities given the NBEUB’s rate
design goals of equity and adaptability for future changes as
addressed in the Board Decision on Matter 357.

Questions:
(a) In regards to Exhibit NBP 07.16 please explain why purchases (less
exports) of $331.127 million are not allocated seasonally (as shown in
Schedule 3.2) but instead uses the ‘average demand’ allocator, given
the Elenchus explanation of the scenario referenced above. Please
explain your reasoning in light of the significant monthly variation
for net purchases as shown in Schedule 1.6.
(b) Please provide any analysis or ‘working papers’ NB Power or
Elenchus undertook with regard to purchases (less exports) regarding
classification and cost allocation, including especially where the
work undertaken lead to the conclusion to not include in
seasonal/monthly allocations.
(c) Please also explain why NBP determined not to allocate purchases
(less exports) of $331.127 million on a monthly basis in Exhibit NBP
7.14, instead again choosing to use the average demand allocator (as
seen in Schedule 3.2). In your response, please explain your reasoning
in light of the significant monthly variation for net purchases as
shown in Schedule 1.6.
(d) Please provide versions of NBP 07.14 and NBP 07.16 that allocate
purchases (less exports) on a monthly and seasonal basis respectively.
(e) Please identify what years Schedules 1.5 and 1.6 from Exhibits NBP
07.14 and 07.16 are based on.
(i) If Schedules 1.5 and 1.6 are not based on the 2020-2021 fiscal
year budget, please explain the rationale behind using a different
year for the data.
(ii) please provide Schedules 1.5 and 1.6 for the 2021-21 fiscal year
budget, for both Exhibits NBP 07.14 and NBP 07.16.
(iii) Please explain how these values are used for the monthly and
seasonal distribution of average-demand classified costs.
(iv) Please correlate net purchases from Schedule 1.6 of $355.003
million to the net purchases allocated on the basis of average demand
in Schedule 3.2 and 4.2 of $331.127 million.
(f) For direct-assigned fuel to the interruptible/surplus Large
Industrial rate class – please explain how the $28.813 million (i.e.
quantity and price) is derived and compare to the tracked monthly and
seasonal allocated fuel quantity and prices (e.g. in Exhibit NBP
7.14).
(g) Please provide the interruptible/surplus sales and related fuel
costs of $28.813 million on a monthly and seasonal basis.
(h) For Exhibit NBP 07.14, please explain how Amortization, OM&A and
interest and net income (deferral account interest) is split by month.
Please reference functionalized monthly allocations as provided in
Schedule 1.5 (Generation by Plant) and Schedule 1.6 (Fuel Cost by
Plant) if these are used to explain the basis of the monthly split for
each of nuclear, thermal and hydro. If these are not used, please
explain what information is.
(i) Please confirm that the seasonal alternative in Exhibit NBP 07.16
is the same methodology as described above, but sums November – March
for the “winter” season and April to October for the “summer” season.
(ii) If not confirmed, please explain the methodology used and why it
was different than the monthly scenario.
(i) For Schedule 4.2, Column 12 ‘Energy Efficiency Specific’ customer
allocations and total of $17.778 million as provided in Exhibit NBP
07.14 and NBP 07.16 (as well as the proposed CCAS model provided in
Exhibit NBP 1.20), please reconcile the allocation and total to the
currently approved CCAS model provided in Exhibit NBP 1.15. In your
response, please specifically highlight if there are offsetting costs
and customer allocated impacts occurring elsewhere in the CCAS model
as a result of the change.
(i) Please reference the CCAS model that this stepped change is
highlighted in (eg. NBP Exhibit 1.18) and detail the methodological
change taking place in the model.
(j) Please fully explain the rationale for each of the cost of service
steps that are experiencing a methodological change including -
functionalization, classification, allocation and direct-assign.
NB Power (JDI)
IR-2
March 23, 2023
Reference:
Exhibit NBP 07.25 Attachment to JDI IR-15a – Load Factor vs. Usage
Questions:
(a) In respect of the “large transmission” class noted in Exhibit
1.11, page iii, what is the test for “large”?
(b) Please confirm (or otherwise explain) that the entire group of
transmission connected customers are included in this class,
regardless of their size.
(c) Exhibit NBP 7.25 references 24 accounts for the ‘IB – Large
Industrial’ rate category in the Transmission subcategory. Meanwhile,
Table 10 from NBP Exhibit 7.18 states there are 41 customers at this
level. Please explain why the full 41 accounts were not provided.
(d) Please provide an updated Exhibit 07.25 for all 41 accounts. To
the extent there are any ‘confidentiality’ concerns and values must be
omitted, provide the rows that are public and provide stand in or
proxy amounts (i.e. approximate values that won’t divulge
confidentiality that give context to magnitude and usage profiles) in
comparison to the other transmission accounts.
(e) With respect to the accounts noted in (d), please also provide
NCP, coincident peak, and annual load factor per account.
NB Power (JDI)
IR-3
March 23, 2023
Reference:
Exhibit NBP04.76, NBP(PI) IR-15a Attachment – Working Papers –
Bill_Impact_Deciles
Exhibit BP04.01, In response to NBP-NBEUB IR-8 where the NBEUB asks
under Alternative 4 if customers with a high bill index would be
paying bills consistent with cost causation principles, NB Power
states that:
For Alternative 4, the basis of Table 3.6a, prices are set at unit
cost. Therefore, by definition, each customer is moved to full cost
coverage.
Questions:
a) If Alternative 4 is adopted as a result of this proceeding, is the
unit cost billing approach the plan NB Power is going to propose
pursuing to enact differential rate adjustments? If not, please
explain.
b) For the working papers listed above - specifically tabs
‘b_alt4_by_orig_rate’ and ‘b_alt_4’ – please provide the calculation
inputs for each tab for the Large Industrial customers including unit
costs, underlying rates used, data year, load factors, etc. underlying
each calculation. Please provide by decile.
c) For the unit costs used to calculate the bill impacts, please
indicate the specific CCAS model used (i.e. the year used for input
data, methodology, etc.) and provide the reference to the specific
schedule for the unit cost values used.
d) If the analysis done in the referenced working paper did not use
CCAS methodology for revenue calculations, but instead used unit costs
to calculate ‘alt_bill” please specify how Out-Of-Province revenue
allocations have been incorporated.
NB Power (JDI)
IR-4
March 23, 2023
Reference:
In NB Power’s Application for the AMI Capital Project (Matter 452,
Exhibit NBP 1.03) it listed three fundamental shifts impacting the
electricity industry to justify the expenditure:
(a) Transformational changes with respect to advancing technology,
including falling distributed energy resources, customer
owned-generation, transportation electrification and electricity
system operational advancements (including AMI);
(b) Evolving customer expectations and demands to control their energy
needs (including to self-generate from renewable resources); and
(c) Climate change requiring a fundamental shift in the supply-side
options to meet customer needs, which NB Power is investing in as part
of its Energy Smart NB Plan. [summarized from Application pages 4-6].
In Exhibit NBP04.01, responding to NBP (NBEUB) IR-11a&b NB Power
explains it does not have current plans for Customer Energy solutions
past its water heating, area lighting and Sureconnect plans, but
believes expanded product offerings could be available that meet these
conditions in the next 5 years.
In Exhibit NBP04.01, responding to NBP (NBEUB) IR-16, NB Power states
it has not evaluated potential Canadian Electricity Regulation (CER)
impacts as they remain uncertain with anticipated release of the CER
by the federal government in 2023, however NB Power notes it supports
the provincial governments net-zero electricity emissions by 2035
goal.
Questions:
(a) With regard to the “fundamental shifts” articulated by NBP
including evolving customer expectations to control their energy
needs/costs and pending regulations/goals that will push NB Power’s
electricity supply towards decarbonization, what considerations has NB
Power included in its rate design proposal that will help support
these requirements?
(i) Please provide a specific response with regard to the large
commercial and industrial customer rate classes.
(b) Please explain how NB Power’s near-term customer segmentation and
differential rate adjustment plans support the three ‘fundamental
shifts’ described above.

On 3/23/23, David Amos <david.raymond.amos333@gmail.com> wrote:
> Good Day,
>
> Please find attached my IRs in PDF and Word.
>
> David Raymond Amos
>

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