NWT Public Utilities Board (BR) Utilities Board BR.NTPC-1 July 20, 2016 Page 1 of 8 ... employee future benefits deferral account increasing because of a new actuarial study and

NWT Public Utilities Board

(BR)

Information Request

NTPC 2016/17 Interim Rate Application

Public Utilities Board

BR.NTPC-1

July 20, 2016 Page 1 of 8

Topic: Interim Rate Increase

Reference: Interim Application Dated June 30, 2016; GRA Schedule 3.1-1; Schedule 1

Preamble:

The Corporation is proposing 2016/17 interim rates be implemented on an equal percentage

basis to existing energy rates for all customers in all zones.

Requests:

a) By reference to GRA Schedule 3.1-1 please provide a summary Schedule showing the

major contributors to the revenue shortfall in each of the Zones. Identify the reasons for

the cost and revenue changes that are contributing to the revenue shortfalls by Zone.

Identify any changes in costs arising from change in the head office cost allocation

method, change in accounting standards/policy as well as changes arising from untested

amortization policy or parameters.

b) GRA Schedule 3.1 indicates the required increase for the Taltson Zone to be 38%

whereas the required increases for the Snare and Thermal Zones are 5.3% and 5.1%

respectively. Did NTPC consider a higher interim rate increase for the Taltson Zone

relative to the Snare and Thermal Zones so as the recover the forecast shortfall more

equitably? Please discuss interim rate mechanisms (example cents/kWh varying by

Zone) that may facilitate a more equitable recovery of shortfalls by Zone with supporting

schedules and discuss the pros and cons thereof.

c) Schedule 1 filed as part of the interim application indicates that an across the board

percent increase of 4.8% would result in a much higher cents per kWh increase for

Government customers in communities where the existing rates are already high,

compared with communities where existing rates are relatively low. For example,

general service customers in Nahanni Butte who are currently paying a rate of $2.7551

per kWh would see an increase of 13.22 cents per kWh. Did NTPC consider other

approaches to implementing rate increases within the Thermal Zone without further

exacerbating the existing high rate levels? Please discuss interim rate mechanisms

(example cents/kWh varying by Government and non Government classes) that may

facilitate a more equitable recovery of Thermal Zone shortfalls by rate class with

supporting schedules and discuss the pros and cons thereof.

Information Request



BR.NTPC-1


Responses:

(a)

Please refer to Attachment BR.NTPC-1(a) comparing the 2016/17 shortfall by zone to the

2013/14 shortfall by zone.

Corporate Budgeting Changes since the 2012/14 GRA

For the 2012/14 GRA the budgeting and tracking system for operations and maintenance

expenses did not use FERC accounts. NTPC employed a tracking and budgeting system by

cost center consistent with the Corporations accounting system. For the 2012/14 GRA this was

addressed in response to YK/HR.NTPC-1 and at the hearing. For the 2016/19 GRA, the

Corporation budgets and tracks costs by cost center as well as by function group as shown in

Schedules 5.0 to 5.1-3 and with variance explanations in Schedule 5.2. When comparing the

2013/14 Test Year to the 2016/17 Test Year the variances by function are mainly attributed to

the different forecasting methods. The Corporation also created a customer service division and

consolidated the transmission and distribution costs. These changes are reclassified from direct

plant costs to common costs.

Variance explanations are provided by zone below.

Snare Zone

The Corporation has reclassified operations and maintenance expenses between plant and

regional/corporate costs. These budgeting changes contribute to the majority of the $0.880

million increase in common operating and maintenance costs and the marginal increase to plant

operating and maintenance costs. Please refer to Chapter 5 of the 2016/19 GRA for further

explanation of changes in operating and maintenance expenses. Production fuel costs have

increased due to the increased base load diesel generation in Yellowknife. Fixed asset

amortization and return on Rate Base for plant and common costs increased as a result of

investment in gross plant and the 2016 Amortization Study. Deferred charges amortization has

increased due to costs incurred to maintain the water licences at Bluefish and Snare. The higher

annual costs relate to increased environmental monitoring at Bluefish dam and increased costs

related to dam inspections as a result of dam safety reviews, required flood surveys and

increased costs relating to annual dam testing and inspections.

Information Request



BR.NTPC-1


The sales impact on revenue to cost ratios, as discussed in Chapter 2 of the GRA, on the Snare

system, are related to decreased sales to the wholesale customer and the industrial customer.

The residential class is forecast to have slightly higher sales in 2016/17 compared to 2013/14.

Sales to general service customers are forecast to be somewhat lower in 2016/17 compared to

2013/14. Common cost deferred amortization expense has increased due to increased

regulatory reporting charged to the regulatory deferral account and the employee future benefits

deferral account increasing because of a new actuarial study and higher than forecast employee

turnover.

Taltson Zone


regional/corporate costs. This is one reason for the $0.808 million increase in common

operating and maintenance costs and the marginal increase to plant operating and maintenance

costs. Please refer to Chapter 5 of the GRA for further explanation to changes in operations and

maintenance expenses. Fixed asset amortization and return on Rate Base for plant and

common costs increased due to investment in gross plant and the 2016 Amortization Study.

The sales impact on revenue to cost ratios as discussed in Chapter 2 of the GRA, on the

Taltson zone, are forecast to be relatively flat for 2016/17 compared to 2013/14. Decreases in

sales to the wholesale customer are forecast (1.4 GWh lower in 2016/17 compared to 2013/14

forecasts). These lower forecasts for wholesale sales in 2016/17 are consistent with the

decrease in actual sales from 2013/14 to 2014/15. Modest growth is forecast for residential

sales (0.5 GWh) and general service sales (0.4 GWh) reflecting higher average use per

customer. Common cost deferred amortization expense has increased due to increased

regulatory reporting charged to the regulatory deferral account and the employee future benefits

deferral account increasing because of a new actuarial study and higher than forecast employee

turnover.

Thermal Zone


regional/corporate costs. This is one reason for the $1.927 million increase in common

operating and maintenance costs and the reduction to plant operating and maintenance costs.

Please refer to Chapter 5 of the GRA for further explanation to changes in operating and

maintenance expenses. Production fuel and purchased power prices are lower due to lower fuel

Information Request



BR.NTPC-1


prices. Fixed asset amortization and return on Rate Base for plant and common costs increased

due to investment in gross plant and the new amortization study. Deferred charges amortization

has increased as a result of costs incurred for engine overhauls. In particular for 2016/17

overhauls in Inuvik are higher as the larger units are due for major overhauls.

The sales impact on revenue to cost ratios as discussed in Chapter 2 of the GRA, in the

Thermal zone largely reflect decreased sales units to general service customers (3.7 GW.h

lower compared to 2013/14 forecasts). These decreases are consistent with actual decreases

between 2013/14 and 2014/15 and reflect lower average use per customer. Sales decreases for

residential customers also reflect somewhat lower average use per customer. Sales decreases

for street lighting customers reflect the conversion of streetlights from mercury vapour and high

pressure sodium lamps to LED. Common cost deferred amortization expense has increased

due to increased regulatory reporting charged to the regulatory deferral account and the

employee future benefits deferral account increasing because of a new actuarial study and

higher than forecast employee turnover.

Impact of head office cost allocation method

Please refer to Attachment BR.NTPC-1(a) that shows the change in head office allocation

between Test Years.

Impact of accounting standards/policy

As discussed in Chapter 5 of the 2016/19 GRA, the Corporation has added one full time

equivalent position, a Management Accountant for regulatory and PSAS accounting. The costs

for the transition to Public Sector Accounting Standards are included in deferred expenses and

discussed on page 11-48 of the 2016/19 GRA. These costs are also reflected in Schedule 11.5

of the 2016/19 GRA.

Impact of Amortization Study

Table 6.2 of the GRA shows the changes to plant amortization expense from the 2013/14 Test

Year to the 2018/19 Test Year. Table 1 below shows the same analysis but for the 2016/17 Test

Year.

Information Request



BR.NTPC-1


Table 1

Amortization Expense Change from 2013/14 Test Year to 2016/17 Test Year ($000s)

The changes that result from the 2016 Amortization Study is the total of the Increased

Amortization Rates, Negative Salvage Collection and True-Up Provision change. These three

items total $0.236 million on a corporate wide basis. The amortization expense increased by

$1.938 million between the Test Years and the Amortization Study accounts for 12% of the

change. The majority of the change is a result of asset additions.

(b)

The Corporation filed revised versions of the GRA schedules with the Board and interveners on

July 12, 2016. The revised rate version of Schedule 3.1-1 2016/17 Revenue Requirement by

Zone shows the average percentage rate increase required to be 5.6% for the Snare zone;

30.8% for the Taltson zone and 5.9% for the Thermal zone.

The Corporation notes that the breakdown of Revenue Requirement by zone is provided solely

for illustrative purposes as part of the 2016/19 Phase I Application. Cost allocations are still

subject to change and will be reviewed as part of the next Phase II General Rate Application.

Changes to cost allocation methods will change the revenue to cost coverage ratios for each

zone. In particular, the allocation of Hydro region costs between the Snare and Taltson zones

and the allocation of the Corporations corporate common costs among all zones is a matter for

review during the Corporations Phase II Application. The Corporation also notes there are a

number of directives included in Board Decision 7-2016 related to the Corporations 2014 cost

of service study. Changes to cost of service methods as a result of completing the Boards cost

of service directives would change the required rate increase percentages for each zone. As a

result, the Corporation considers that the zone based information provided as part of the Phase

I filing should be considered illustrative and primarily provided for information purposes at this

Information Request



BR.NTPC-1


time. Revenue to cost coverage ratios will be subject to change as part of the review of the

Phase II General Rate Application.

The Corporation believes that its proposed interim rates are equitable and notes the following:

1. The Corporation is seeking to transition customers to an overall Revenue Requirement

that is approximately 13% higher than current rate levels. Over a three year period this

requires average rate increases of slightly more than 4% per year. The Corporations

2016/17 interim rates were developed to provide a first step toward the required revenue

increases keeping in mind the rate stabilization fund refund rider approved for

implementation in 2016 offsets some of the increase to base electricity rates.

2. The proposed increases of 4.8% to the energy rates are lower than the total average

2016/17 percentage increase required for each zone as shown in Schedule 3.1-1

revised July 12, 2016 of 5.6% for the Snare zone; 30.8% for the Taltson zone and 5.9%

for the Thermal zone. On that basis, no zone is forecast to pay rates that result in

revenues higher than the forecast Revenue Requirement for 2016/17.

3. The Corporation is following common regulatory practice as other electric utilities have

received approvals for interim rate increases on an equal percentage basis:

a. The Manitoba Public Utilities Board recently approved a 3.36% interim rate

increase to existing rates for all of Manitoba Hydros customer classes.1

b. The Alberta Utilities Commission approved ENMAX Power Corporations

application for an interim rate of 3.19% to be applied to all rate classes on an

across-the-board basis effective January 1, 2015. In its Decision, the AUC noted

in part that this method is simple and cost effective to apply.2

4. The 2015 GNWT guidelines limited rate increases due to rebalancing to no more than

3% until the time of the next Phase II GRA.3 If the Corporation were to increase rates for

the Taltson zone by 7.8% (that is, 3% higher than the average rate increase sought

Corporation-wide), it would reduce the rate increase required for the Snare and Taltson

zones by only a very small amount to 4.55% to generate the same interim rate revenues

1 Manitoba Public Utilities Board Decision 59-16 Available: http://www.pub.gov.mb.ca/pdf/16hydro/59-

16.pdf 2 Alberta Utilities Commission Decision 2014-311 Available:

http://www.auc.ab.ca/applications/decisions/Decisions/2014/2014-311.pdf 3 Guideline 1. April 2015 GNWT Guidelines.

http://www.pub.gov.mb.ca/pdf/16hydro/59-16.pdfhttp://www.pub.gov.mb.ca/pdf/16hydro/59-16.pdfhttp://www.auc.ab.ca/applications/decisions/Decisions/2014/2014-311.pdf

Information Request



BR.NTPC-1


in 2016/17. The proof of revenue for this scenario is provided in Attachment BR.NTPC-

1(b). In the Corporations view there is little impact on rates for the other zones, and this

approach complicates the Interim Rate Application and is more difficult to explain to

customers.

NTPCs long-standing rate strategy has been to work towards a 90-110% range for revenue to

cost ratios for all zones. In targeting the 90-110% RCC, NTPC balances other rate design

criteria such as gradualism and predictability for customers. As a small utility with small rate

zones, Revenue Requirement changes that might not materially impact revenue to cost ratios in

other jurisdictions can have large impacts for NTPCs rate zones. In addition RCC ratios are not

static over time. For example, sales growth forecasts, investment in hydro and transmission

facilities; major overhauls requirements and other factors are not uniformly distributed across

zones and may change the RCC ratios significantly. The Corporation notes that many other

utilities use a range of reasonableness for revenue to cost coverage ratios:

Manitoba Hydros long-term target is to have all class revenue to cost coverage ratios in

the range of 95% to 105%.4

SaskPower has a revenue to revenue requirement target ratio of 0.95 to 1.05.5

The Yukon Utilities Board has previously approved a target revenue to cost coverage

range of between 90% to 110%.6

On this basis, the Corporation believes its proposed interim rates are equitable and consistent

with good utility practice.

(c)

The Corporation prepared its Interim Rate Application based on the criteria described in the

Application. For the reasons noted in response to BR.NTPC-1 (b), the Corporation believes it

proposed interim rates are equitable. Further, the Corporation notes that Guideline 3 from the

2015 GNWT guidelines states that realignment of community based rates for Government

customers shall be deferred until the next Phase II GRA. Guideline 3 is also designed to

4 Manitoba Hydro 2015/16 & 2016/17 General Rate Application. Available:

https://www.hydro.mb.ca/regulatory_affairs/electric/gra_2014_2015/pdf/tab_6.pdf 5 Ministers Terms of Reference for Review of SaskPowers 2016 and 2017 rate application. Available:

http://www.saskratereview.ca/docs/saskpower2016/mo-saskpower.pdf 6 Yukon Utilities Board Decision 1996-7. Available:

http://yukonutilitiesboard.yk.ca/pdf/Board%20Orders%201990/63_boardorder1996_7.pdf

https://www.hydro.mb.ca/regulatory_affairs/electric/gra_2014_2015/pdf/tab_6.pdfhttp://www.saskratereview.ca/docs/saskpower2016/mo-saskpower.pdfhttp://yukonutilitiesboard.yk.ca/pdf/Board%20Orders%201990/63_boardorder1996_7.pdf

Information Request



BR.NTPC-1


achieve a zonal based government rate as opposed to the current community based

Government rates. In the Corporations view Guideline 3 is not intended to make Government

rates equal non-Government rates by zone. Guideline 3 from the 2010 GNWT Rate Policy

Guidelines states that government customers can have higher electricity base rates than non-

government customers in the same community for the same type of service, but not lower than

non-government customers. The Corporations proposed interim rate design is consistent with

both of these guidelines and will result in government customers continuing to pay rates that are

the same or higher as other customers in the same rate community.

For illustrative purposes, the Corporation prepared an analysis of a potential equal cent/kWh

increase where there is currently a large variation between government and non-government

rates within a zone. The largest energy rate variations between government and non-

government rates occur in the Thermal zone. The difference between government and non-

government rates in the Snare and Taltson zones are relatively small on a cents/kWh basis. An

interim rate increase of 4.36 cents per kWh for all government customers would result in the

same interim rate revenues as the Corporations proposed 4.8% increase to all energy rates.

The analysis is provided in Attachment BR.NTPC 1(c).

Attachment BR.NTPC-1(a)

Line 2013/14 2016/17

No. Test Year Test Year Change

1 Non-Fuel Operation & Maintenance Expense

2 Salaries and Wages 4,205 3,798 (406)

3 Non-Production Fuel and Lubricants 223 207 (16)

4 Supplies and Services 3,049 3,816 767

5 Travel and Accommodation 252 324 72

6 Total Non-Production Fuel Operation & Maintenance Expense 7,728 8,145 417

7 Less: Corporate Donations 60 78 18

8 Total Non-Production Fuel Operation & Maintenance Expense for GRA 7,668 8,067 399

9 Production Fuel Expense

10 Fuel 338 932 594

11 Purchased Power

12 Total Production Fuel Expense 338 932 594

13 Amortization

14 Fixed Asset Amortization (less Customer Contributions) 5,836 6,507 671

15 Amortization of Deferred Charges 581 1,516 935

16 Total Amortization Expense 6,417 8,023 1,606

17 Total Return on Rate Base 11,267 11,162 (104)

18 Total Zone Specific Revenue Requirement 25,689 28,185 2,495

Common Cost Allocation by Zone

19 Corporate Sales Share 58.24% 58.16% -0.08%

20 Hydro Sales Share 76.38% 75.72% -0.66%

21 Corporate O&M Expenses 7,321 7,789 468

22 Hydro Regional O&M Expenses 468 576 108

23 Thermal Regional O&M Expenses

24 Distribution Related Common O&M Expenses 156 459 303

25 Total Allocated Common Cost O&M 7,945 8,825 880

26 Corporate Amortization 825 1,078 253

27 Hydro Regional Amortization 98 187 89

28 Thermal Regional Amortization

29 Distribution Related Common Amortization 6 3 (3)

30 Amortization of Deferred Charges 924 1,349 425

31 Total Allocated Common Cost Amortization 1,853 2,617 764

32 Corporate Return on Ratebase 879 1,039 160

33 Hydro Regional Return on Ratebase 127 241 114

34 Thermal Regional Return on Ratebase

35 Distribution Related Return on Ratebase 13 1 (12)

36 Total Allocated Common Cost Return on Ratebase 1,019 1,281 262

37 Total Revenue Requirement 36,506 40,907 4,401

38 Other Revenue 74 118 44

39 Net Revenue Requirement 36,432 40,789 4,357

40 Revenue from Sales 40,124 38,629 (1,495)

41 Shortfall / (Surplus) (3,692) 2,160 5,852

42 Average Rate Increase Required -9.2% 5.6%

NORTHWEST TERRITORIES POWER CORPORATION

2016/17 INTERIM RATE APPLICATION

SNARE ZONE REVENUE REQUIREMENT

(in thousands of dollars)

2016/17 NTPC Interim Rate Application


Line 2013/14 2016/17




3 Non-Production Fuel and Lubricants 51 60 9

4 Supplies and Services 1,295 1,439 144

5 Travel and Accommodation 193 117 (76)

6 Total Non-Production Fuel Operation & Maintenance Expense 3,400 3,273 (127)


8 Total Non-Production Fuel Operation & Maintenance Expense for GRA 3,381 3,248 (133)


10 Fuel 289 276 (13)

11 Purchased Power

12 Total Production Fuel Expense 289 276 (13)

13 Amortization


15 Amortization of Deferred Charges 713 793 80

16 Total Amortization Expense 1,851 1,990 139

17 Total Return on Rate Base 1,659 1,887 228

18 Total Zone Specific Revenue Requirement 7,181 7,401 220


19 Corporate Sales Share 18.01% 18.65% 0.64%

20 Hydro Sales Share 23.62% 24.28% 0.66%


22 Hydro Regional O&M Expenses 145 185 40

23 Thermal Regional O&M Expenses 0

24 Distribution Related Common O&M Expenses 247 798 551

25 Total Allocated Common Cost O&M 2,673 3,481 808

26 Corporate Amortization 255 346 91

27 Hydro Regional Amortization 30 60 30

28 Thermal Regional Amortization



31 Total Allocated Common Cost Amortization 580 843 262

32 Corporate Return on Ratebase 272 333 61

33 Hydro Regional Return on Ratebase 39 77 38

34 Thermal Regional Return on Ratebase


36 Total Allocated Common Cost Return on Ratebase 332 412 80

37 Total Revenue Requirement 10,766 12,137 1,371

38 Other Revenue 208 418 210

39 Net Revenue Requirement 10,558 11,719 1,161

40 Revenue from Sales 8,949 8,961 11

41 Shortfall / (Surplus) 1,609 2,759 1,150

42 Average Rate Increase Required 18.0% 30.8%



TALTSON ZONE REVENUE REQUIREMENT




Line 2013/14 2016/17




3 Non-Production Fuel and Lubricants 603 926 323

4 Supplies and Services 4,446 3,673 (773)

5 Travel and Accommodation 962 719 (243)

6 Total Non-Production Fuel Operation & Maintenance Expense 13,303 12,585 (717)


8 Total Non-Production Fuel Operation & Maintenance Expense for GRA 13,273 12,554 (719)


10 Fuel 24,025 20,124 (3,901)

11 Purchased Power 2,978 2,068 (910)

12 Total Production Fuel Expense 27,003 22,192 (4,811)

13 Amortization


15 Amortization of Deferred Charges 2,467 3,241 774

16 Total Amortization Expense 8,336 9,772 1,436

17 Total Return on Rate Base 4,381 4,991 610

18 Total Zone Specific Revenue Requirement 52,993 49,509 (3,484)


19 Corporate Sales Share 23.75% 23.19% -0.56%

20 Hydro Sales Share


22 Hydro Regional O&M Expenses

23 Thermal Regional O&M Expenses 578 871 293

24 Distribution Related Common O&M Expenses 508 2,033 1,525

25 Total Allocated Common Cost O&M 4,083 6,010 1,927

26 Corporate Amortization 336 430 94

27 Hydro Regional Amortization

28 Thermal Regional Amortization 39 53 14



31 Total Allocated Common Cost Amortization 780 1,033 253

32 Corporate Return on Ratebase 368 426 58

33 Hydro Regional Return on Ratebase 0

34 Thermal Regional Return on Ratebase 52 52


36 Total Allocated Common Cost Return on Ratebase 484 481 (3)

37 Total Revenue Requirement 58,341 57,033 (1,308)

38 Other Revenue 775 1,332 557

39 Net Revenue Requirement 57,566 55,701 (1,865)

40 Revenue from Sales 55,483 52,611 (2,872)

41 Shortfall / (Surplus) 2,084 3,090 1,007

42 Average Rate Increase Required 3.8% 5.9%




THERMAL ZONE REVENUE REQUIREMENT


Total 2016/17August 2016 -

March 2017

Total

2016/17

August 2016 -

March 2017

Total

2016/17

August 2016 -

March 2017

Total

2016/17

August 2016 -

March 2017Total 2016/17

August 2016

- March

2017

Total

2016/17

August 2016

- March 2017

Total

2016/17

August

2016 -

March 2017

A B B1 C C1 D=B+C E F F1 G G1 H=F+G I J J1 K L L1 M M1

Snare Zone 352,200 163,417 111,760 20,880 6,192 4,128

125 Behchoko 520 1,218 738 2,999 2,022 4,217 14,672 1,697 1,090 1,391 872 3,088 62 41

126 Dettah 91 255 174 379 260 634 2,211 252 190 87 32 339 8 6

Snare Zone Total 611 1,473 911 3,378 2,282 4,851 16,883 1,949 1,281 1,478 904 3,427 352,200 163,417 111,760 20,880 6,192 4,128 70 47

Taltson Zone 31,149 21,008

Taltson Zone - interrup. 657 431

128 Fort Smith 1,047 1,519 897 9,070 5,381 10,588 48,385 7,846 5,143 3,873 2,516 11,719 232 155

130 Fort Resolution 221 418 279 1,175 699 1,593 6,671 768 507 340 223 1,108 28 18

Taltson Zone Total 1,268 1,937 1,175 10,245 6,080 12,182 55,056 8,614 5,650 4,214 2,739 12,828 - 31,807 21,439 - - - 260 173

Thermal Zone

123 Wha Ti 136 222 148 727 485 949 3,411 538 358 142 95 680 13 8

124 Gameti 87 116 77 438 292 553 3,081 378 252 126 84 504 6 4

127 Lutsel K'e 128 288 192 420 280 709 3,178 501 334 181 121 682 13 9

131 Fort Simpson 517 503 335 2,397 1,598 2,900 19,828 2,486 1,657 1,500 1,000 3,987 49 33

132 Fort Liard 186 195 130 806 537 1,001 5,449 494 329 621 414 1,114 18 12

133 Wrigley 60 82 55 236 157 318 1,946 274 183 22 15 296 9 6

134 Nahanni Butte 36 6 4 167 111 173 1,032 93 62 91 61 184 11 7

135 Jean Marie River 27 9 6 112 75 120 1,122 118 78 22 15 140 4 3

136 Inuvik 1,362 1,411 941 6,414 4,276 7,825 78,050 9,151 6,100 8,094 5,396 17,245 97 65

137 Norman Wells 404 379 253 2,821 1,881 3,200 26,080 1,859 1,239 3,831 2,554 5,691 95 63

138 Tuktoyaktuk 330 1,067 712 1,038 692 2,105 7,597 845 563 698 465 1,543 26 17

139 Fort McPherson 298 618 412 1,007 672 1,626 7,056 874 583 632 421 1,506 25 17

140 Aklavik 255 764 509 670 446 1,433 7,354 775 516 681 454 1,455 68 45

141 Deline 222 565 377 645 430 1,210 6,293 611 407 644 430 1,255 35 23

142 Fort Good Hope 211 262 175 911 607 1,173 5,979 696 464 573 382 1,269 51 34

143 Paulatuk 105 403 269 225 150 628 3,937 502 335 288 192 791 11 7

144 Sachs Harbour 50 169 113 112 75 281 2,587 339 226 202 135 541 13 8

145 Tsiigehtchic 69 106 71 213 142 319 2,142 219 146 97 65 316 8 5

146 Colville Lake 41 0 0 224 150 225 1,402 188 126 131 88 320 3 2

147 Ulukhaktok 153 554 369 290 193 844 5,210 663 442 395 263 1,058 9 6

148 Tulit'a 183 473 315 684 456 1,157 5,904 646 431 409 273 1,056 22 15

Thermal Region Total 4,860 8,191 5,461 20,557 13,705 28,748 198,637 22,250 14,833 19,381 12,921 41,631 - - - - - - 586 391

Total 6,739 11,601 7,547 34,180 22,067 45,781 270,576 32,813 21,764 25,073 16,564 57,886 352,200 195,224 133,199 20,880 6,192 4,128 916 611

Government Non-Government

Total

Government Non-Government

Energy Sales Forecast (MW.h)

Demand

Forecast

(kW)

Energy Sales Forecast

(MW.h)Demand

Forecast (kW)

Energy Sales Forecast

(MW.h)

BR.NTPC 1(b)


2016/17 Interim Rate Application

Plant

NumberCommunity Name

2016/17 Sales Forecast

Residential General Service Wholesale

Total

Industrial

Lighting (MWh)

Number of

Customers

Energy Sales Forecast (MW.h)

Billed Demand

Forecast (kW)


Existing Rates

Proposed

Interim rates

Effective

August 1, 2016

Existing

Rates

Proposed

Interim

rates

Effective

August 1,

2016

Existing Rates

Proposed

Interim rates

Effective

August 1, 2016

Existing

Rates

Proposed

Interim rates

Effective

August 1,

2016

Existing

Rates

Proposed

Interim rates

Effective

August 1,

2016

Existing Rates

Proposed

Interim

rates

Effective

August 1,

2016

Existing

Rates

Proposed

Interim rates

Effective

August 1,

2016

A A1 B B1 C C1 D D1 E E1 F F1 G G1 H H1 I I1 J J1 K K1

Snare Zone 8.10 0.00 19.21 0.87 11.76 0.00 14.99 0.68

125 Behchoko 32.06 1.46 31.10 1.41 18.00 - 39.47 1.79 38.29 1.74 8.00 - 92.04 4.18

126 Dettah 35.76 1.63 31.10 1.41 18.00 - 44.32 2.01 38.29 1.74 8.00 - 78.69 3.58

Snare Zone Total

Taltson Zone 10.83 0.82

Taltson Zone - interrup. 5.42 0.41

128 Fort Smith 21.00 1.58 21.00 1.58 18.00 - 16.53 1.25 16.53 1.25 8.00 - 31.05 2.34

130 Fort Resolution 26.63 2.01 21.00 1.58 18.00 - 23.14 1.75 16.53 1.25 8.00 - 43.72 3.30

Taltson Zone Total

Thermal Zone

123 Wha Ti 108.55 4.93 60.83 2.76 18.00 - 100.76 4.58 51.60 2.35 8.00 - 178.26 8.10

124 Gameti 166.60 7.57 60.83 2.76 18.00 - 191.48 8.70 51.60 2.35 8.00 - 214.15 9.73

127 Lutsel K'e 100.80 4.58 60.83 2.76 18.00 - 93.74 4.26 51.60 2.35 8.00 - 160.31 7.29

131 Fort Simpson 94.26 4.28 60.83 2.76 18.00 - 82.58 3.75 51.60 2.35 8.00 - 105.74 4.81

132 Fort Liard 100.19 4.55 60.83 2.76 18.00 - 90.32 4.11 51.60 2.35 8.00 - 154.60 7.03

133 Wrigley 177.03 8.05 60.83 2.76 18.00 - 189.31 8.60 51.60 2.35 8.00 - 246.53 11.21

134 Nahanni Butte 213.58 9.71 60.83 2.76 18.00 - 275.51 12.52 51.60 2.35 8.00 - 327.79 14.90

135 Jean Marie River 190.86 8.67 60.83 2.76 18.00 - 257.54 11.71 51.60 2.35 8.00 - 344.03 15.64

136 Inuvik 77.46 3.52 60.83 2.76 18.00 - 68.90 3.13 51.60 2.35 8.00 - 90.86 4.13

137 Norman Wells 57.39 2.61 47.54 2.16 18.00 - 52.14 2.37 43.20 1.96 8.00 - 76.65 3.48

138 Tuktoyaktuk 90.87 4.13 60.83 2.76 18.00 - 80.70 3.67 51.60 2.35 8.00 - 123.30 5.60

139 Fort McPherson 104.72 4.76 60.83 2.76 18.00 - 95.80 4.35 51.60 2.35 8.00 - 116.99 5.32

140 Aklavik 83.22 3.78 60.83 2.76 18.00 - 79.52 3.61 51.60 2.35 8.00 - 112.09 5.09

141 Deline 106.79 4.85 60.83 2.76 18.00 - 100.76 4.58 51.60 2.35 8.00 - 91.58 4.16

142 Fort Good Hope 92.94 4.22 60.83 2.76 18.00 - 81.40 3.70 51.60 2.35 8.00 - 108.37 4.93

143 Paulatuk 157.77 7.17 60.83 2.76 18.00 - 149.08 6.78 51.60 2.35 8.00 - 174.71 7.94

144 Sachs Harbour 195.25 8.87 60.83 2.76 18.00 - 183.01 8.32 51.60 2.35 8.00 - 209.33 9.51

145 Tsiigehtchic 144.67 6.58 60.83 2.76 18.00 - 128.15 5.82 51.60 2.35 8.00 - 183.38 8.33

146 Colville Lake 295.55 13.43 60.83 2.76 18.00 - 257.04 11.68 51.60 2.35 8.00 - 735.56 33.43

147 Ulukhaktok 90.81 4.13 60.83 2.76 18.00 - 82.20 3.74 51.60 2.35 8.00 - 119.95 5.45

148 Tulit'a 114.89 5.22 60.83 2.76 18.00 - 110.97 5.04 51.60 2.35 8.00 - 132.46 6.02

Energy Rates, cents/kW.h

Demand

Charge,

$/kW/month

Plant


2016/17 Existing and Proposed Interim Rates

Residential General Service

Interim

Demand

Charge,

$/kW/month

Demand

Charge,

$/kW/month

Interim

Demand

Charge,

$/kW/month

Energy Rates, cents/kW.h

Demand

Charge,

$/kW/month

Interim

Demand

Charge,

$/kW/month

Streetlight, cents/kW.h

Wholesale Industrial

Government Energy Rates,

cents/kW.h

Non-Government Energy

Rates, cents/kW.hCustomer

Charge,

$/customer/

month

Interim

Customer

Charge,

$/customer/

month

Government Energy Rates,

cents/kW.h

Non-Government Energy

Rates, cents/kW.h

BR.NTPC 1(b)




GovernmentNon-

GovernmentTotal Government

Non-

GovernmentTotal

A B C=A+B D E=C+D F G H=F+G I J=H+I K L M N=L+M O P Q=O+PR=E+J+K+N

+Q

Snare Zone - 976 976 - 28 28 1,004

125 Behchoko 11 29 39 - 39 20 15 35 - 35 2 76

126 Dettah 3 4 7 - 7 4 1 4 - 4 0 11

Snare Zone Total 14 32 46 - 46 23 16 39 - 39 2 976 976 28 28 1,091

Taltson Zone 172 172 - 172

Taltson Zone - interrup. 2 2 - 2

128 Fort Smith 14 85 99 - 99 64 31 96 - 96 4 199

130 Fort Resolution 6 11 17 - 17 9 3 12 - 12 1 29

Taltson Zone Total 20 96 116 - 116 73 34 107 - 107 4 173 173 - 401

Thermal Zone

123 Wha Ti 7 13 21 - 21 16 2 19 - 19 1 40

124 Gameti 6 8 14 - 14 22 2 24 - 24 0 38

127 Lutsel K'e 9 8 17 - 17 14 3 17 - 17 1 34

131 Fort Simpson 14 44 59 - 59 62 23 86 - 86 2 146

132 Fort Liard 6 15 21 - 21 14 10 23 - 23 1 45

133 Wrigley 4 4 9 - 9 16 0 16 - 16 1 26

134 Nahanni Butte 0 3 3 - 3 8 1 9 - 9 1 14

135 Jean Marie River 0 2 3 - 3 9 0 10 - 10 0 13

136 Inuvik 33 118 151 - 151 191 127 318 - 318 3 472

137 Norman Wells 7 41 47 - 47 29 50 80 - 80 2 129

138 Tuktoyaktuk 29 19 49 - 49 21 11 32 - 32 1 81

139 Fort McPherson 20 19 38 - 38 25 10 35 - 35 1 74

140 Aklavik 19 12 32 - 32 19 11 29 - 29 2 63

141 Deline 18 12 30 - 30 19 10 29 - 29 1 60

142 Fort Good Hope 7 17 24 - 24 17 9 26 - 26 2 52

143 Paulatuk 19 4 23 - 23 23 5 27 - 27 1 51

144 Sachs Harbour 10 2 12 - 12 19 3 22 - 22 1 35

145 Tsiigehtchic 5 4 9 - 9 9 2 10 - 10 0 19

146 Colville Lake 0 4 4 - 4 15 2 17 - 17 1 22

147 Ulukhaktok 15 5 21 - 21 17 6 23 - 23 0 44

148 Tulit'a 16 13 29 - 29 22 6 28 - 28 1 58

Thermal Region Total 247 368 614 - 614 585 293 878 - 878 22 - - - - 1,514

Total 280 496 776 - 776 681 343 1,024 - 1,024 28 1,149 1,149 28 28 3,006

Customer

ChargeTotal

EnergyDemand

Charge

Plant


Revenues from Proposed Interim Rates Effective August 1, 2016 to March 31, 2017 $000

Residential Commercial

Streetlight

Wholesale Industrial

TotalEnergy

Energy Total Demand Energy TotalTotal Demand

BR.NTPC 1(b)




Attachment BR.NTPC 1(c)

MWh MWh MWh (c/kWh) (c/kWh) (c/kWh) $000 $000 $000 $000

A B C D E F G H I J

Government Sales

123 Wha Ti 148 358 8 5.21 4.84 8.56 8 17 1 26

124 Gameti 77 252 4 8.00 9.19 10.28 6 23 0 30

127 Lutsel K'e 192 334 9 4.84 4.50 7.69 9 15 1 25

131 Fort Simpson 335 1,657 33 4.52 3.96 5.08 15 66 2 83

132 Fort Liard 130 329 12 4.81 4.34 7.42 6 14 1 21

133 Wrigley 55 183 6 8.50 9.09 11.83 5 17 1 22

134 Nahanni Butte 4 62 7 10.25 13.22 15.73 0 8 1 10

135 Jean Marie River 6 78 3 9.16 12.36 16.51 1 10 0 11

136 Inuvik 941 6,100 65 3.72 3.31 4.36 35 202 3 240

137 Norman Wells 253 1,239 63 2.75 2.50 3.68 7 31 2 40

138 Tuktoyaktuk 712 563 17 4.36 3.87 5.92 31 22 1 54

139 Fort McPherson 412 583 17 5.03 4.60 5.62 21 27 1 48

140 Aklavik 509 516 45 3.99 3.82 5.38 20 20 2 42

141 Deline 377 407 23 5.13 4.84 4.40 19 20 1 40

142 Fort Good Hope 175 464 34 4.46 3.91 5.20 8 18 2 28

143 Paulatuk 269 335 7 7.57 7.16 8.39 20 24 1 45

144 Sachs Harbour 113 226 8 9.37 8.78 10.05 11 20 1 31

145 Tsiigehtchic 71 146 5 6.94 6.15 8.80 5 9 0 14

146 Colville Lake 0 126 2 14.19 12.34 35.31 0 15 1 16

147 Ulukhaktok 369 442 6 4.36 3.95 5.76 16 17 0 34

148 Tulita 315 431 15 5.51 5.33 6.36 17 23 1 41

Total 5,461 14,833 391 261 618 23 901

Lighting Residential General

Service Total

General

ServiceLighting Residential

General

Service



2016/17 PROPOSED INTERIM RATES AND REVENUES FOR THERMAL ZONE GOVERNMENT CUSTOMERS

Plant

Number

Community

name

August 2016 - March 2017 Energy

Sales ForecastProposed Interim Rates Energy Revenue from Interim Rates

Residential

Revenue

from

Lighting


Attachment BR.NTPC 1(c)

MWh MWh MWh (c/kWh) (c/kWh) (c/kWh) $000 $000 $000 $000

A B C D E F G H I J

Government Sales

123 Wha Ti 148 358 8 4.36 4.36 4.36 6 16 0 22

124 Gameti 77 252 4 4.36 4.36 4.36 3 11 0 15

127 Lutsel K'e 192 334 9 4.36 4.36 4.36 8 15 0 23

131 Fort Simpson 335 1,657 33 4.36 4.36 4.36 15 72 1 88

132 Fort Liard 130 329 12 4.36 4.36 4.36 6 14 1 21

133 Wrigley 55 183 6 4.36 4.36 4.36 2 8 0 11

134 Nahanni Butte 4 62 7 4.36 4.36 4.36 0 3 0 3

135 Jean Marie River 6 78 3 4.36 4.36 4.36 0 3 0 4

136 Inuvik 941 6,100 65 4.36 4.36 4.36 41 266 3 310

137 Norman Wells 253 1,239 63 4.36 4.36 4.36 11 54 3 68

138 Tuktoyaktuk 712 563 17 4.36 4.36 4.36 31 25 1 56

139 Fort McPherson 412 583 17 4.36 4.36 4.36 18 25 1 44

140 Aklavik 509 516 45 4.36 4.36 4.36 22 22 2 47

141 Deline 377 407 23 4.36 4.36 4.36 16 18 1 35

142 Fort Good Hope 175 464 34 4.36 4.36 4.36 8 20 1 29

143 Paulatuk 269 335 7 4.36 4.36 4.36 12 15 0 27

144 Sachs Harbour 113 226 8 4.36 4.36 4.36 5 10 0 15

145 Tsiigehtchic 71 146 5 4.36 4.36 4.36 3 6 0 10

146 Colville Lake 0 126 2 4.36 4.36 4.36 0 5 0 6

147 Ulukhaktok 369 442 6 4.36 4.36 4.36 16 19 0 36

148 Tulita 315 431 15 4.36 4.36 4.36 14 19 1 33

Total 5,461 14,833 391 238 646 17 901

Plant

Number

Community

name

August 2016 - March 2017 Energy Proposed Interim Rates

Lighting

Energy Revenue from Interim Rates

ResidentialGeneral

ServiceLighting Residential

General

ServiceResidential

General

Service

Revenue

from

Lighting

Total



2016/17 INTERIM RATES AND REVENUES FOR THERMAL ZONE GOVERNMENT CUSTOMERS - EQUAL CENTS/KWH


Information Request



BR.NTPC-2


Topic: Revenue Forecast

Reference: Interim Application Dated June 30, 2016; GRA Schedule 2.1-1 to 2.1-3;

Schedule 1

Preamble:

Total forecast sales for 2016/17 are lower relative to the 2013/14 Test Year forecast (14.3

GWh), with an average annual decline in sales of 1.5%. Revenue at existing rates has

decreased by $4.6 million as shown in Table 2.3 in the GRA which is due to the reduction in

sales.

Requests:

a) Schedules 2.1-1, 2.1-2 and 2.1-3 generally reflect declining use per customer for

residential and general service customers in all Zones since 2013/14 actual with some

modest increases forecast for the test years. Please indicate whether some or all of the

declines in sales that occurred in 2014/15 and 2015/16 may be attributed to the

economic impact of the oil price decline in 2014/15.

b) Does NTPC expect residential and general service use per customer to improve to the

levels that existed during 2013/14 and preceding years; if so to what extent and when?

Provide reasons.

c) Please provide the experienced and forecast real GDP growth rates for the NWT for the

period 2013 to 2019. Identify the source documents used for this purpose.

d) To the extent some of the decline in sales in the test period relative to 2013/14 may be

due to an economic downturn, please provide the forecast use per customer for the test

period using the regression analysis described under response to directive 32, but giving

due recognition to the impact of the economic downturn. (example: use of GDP growth

as a second independent variable or, use of dummy variables to represent the economic

downturn)

e) Schedule 2.1-1 indicates the Snare Zone wholesale sales declining from 168.1 Gwh in

2013/14 to 163.4 Gwh in 2014/15 and continuing at this same level for the entire test

Information Request



BR.NTPC-2


period. Please explain why NTPC is not expecting wholesale sales to recover following

2014/15 having regard to GDP growth expectations for Yellowknife.

f) Schedule 2.1-2 indicates the Taltson Zone wholesale sales declining from 2013/14

levels into 2014/15 and 2015/16 and then showing moderate improvement in the test

period but still below 2013/14 levels. Please provide the rationale and support for the

above noted pattern of sales for the Taltson Zone.

Response:

(a) through (f)

The Corporations load forecast was prepared consistent with the methods requested by the

Board in Decision 1-2013. The discussion of the methods used in preparing the load forecast for

the Test Years is provided in Chapter 2 of the 2016/19 General Rate Application. The

Corporations response to the Boards directive with respect to the Corporations load forecast

method is provided in Chapter 13 of the Application. The Corporation believes its load forecast

as provided in Chapter 2 of the Application is reasonable for the purposes of evaluating the

2016/17 Interim Rate Application. The Corporation notes that for the purposes of the Interim

Rate Application, the 2016/17 sales forecast is most relevant. Sales forecasts for the future Test

Years can be reviewed as part of the full 2016/19 General Rate Application proceeding.

Detailed forecast and actual GDP data by year is not readily available for the NWT. Given the

methodology changes suggested by the Board and the complexity to complete the changes, the

Corporation feels it is more suitable to discuss different load forecast methodologies in the

context of the 2016/19 GRA which would have implications on all three Test Years as opposed

to the 2016/17 Interim Rate Application. However the Corporation can provide some additional

information in this response to assist with the understanding of the 2016/17 Test Year load

forecast.

The Corporation notes that the 2013/14 actual sales represented the highest total sales levels

between 2009/10 and 2015/16. The Corporation has observed consistent year over year

decreases in average use per customer from 2013/14 through 2015/16. Table 1 summarizes the

actual and forecast residential, general service and wholesale sales for 2009/10 through

2018/19.

Information Request



BR.NTPC-2


Table 1:

Residential, General Service and Wholesale Sales (MWh)1

Based on a review of the actual historic sales information, the Corporation is of the view that

2013/14 should not be considered a baseline or normal year, but actually represented a year

of unusually high sales.

Using the load forecast methods requested by the Board in Decision 1-2013, the Corporation is

forecasting a small recovery in total sales in 2016/17 compared to 2015/16. However, the

Corporation is not anticipating sales to return to 2013/14 actual levels. Additional information

that the Corporation believes supports the forecast of only a modest recovery in sales in

2016/17 compared to 2015/16 includes:

1. 2013/14 actually represented the highest total sales volumes for the five year period

from 2009/10 through 2013/14. For the years 2010/11 through 2012/13 total sales were

relatively flat, with 2013/14 representing a noticeable increase over previous sales

levels.

2. The GNWTs 2016 fiscal framework notes that the NWT is facing a range of economic

challenges. The economy is currently fragile and thus extremely susceptible to

pressures from outside the territory.2

1 Note: 2009/10 through 2014/15 are actual sales. 2015/16 includes 11 months of preliminary actuals.

2016/17 is the test year forecast included in the Corporations 2016/19 General Rate Application. 2 Government of the Northwest Territories 2016 Fiscal Framework. Available:

http://www.gov.nt.ca/sites/default/files/GNWT%20Fiscal%20Framework%20Summary.pdf

Residential

General

Service Wholesale Total

2009/10 A 44,729 60,729 192,287 297,745

2010/11 A 44,718 60,626 198,658 304,002

2011/12 A 45,015 60,208 197,712 302,935

2012/13 A 46,037 60,829 197,507 304,372

2013/14 A 47,852 60,287 200,870 309,009

2014/15 A 45,454 58,679 196,845 300,978

2015/16 F 44,320 57,987 194,460 296,767

2016/17 F 45,781 57,886 195,224 298,891

http://www.gov.nt.ca/sites/default/files/GNWT%20Fiscal%20Framework%20Summary.pdf

Information Request



BR.NTPC-2


3. A 2015 presentation from the Conference Board of Canada indicated 10-year average

GDP growth of approximately 1% per year from 2015 to 2025.3

4. The GNWT bureau of statistics released a report in May 2016 that showed modest

growth in territorial chained GDP in 2015 compared to 2014.4 However, the following

should be noted in considering this information:

a. The report is based on preliminary information. Final 2015 economic accounts

information is not expected to be available until November 2016.

b. Much of the growth in territorial GDP was driven by an 18.3% GDP increase in

the construction sector. Construction at the Gahcho Kue diamond mine in 2015

contributed to the increases in the construction sector.

c. The preliminary 2015 figures show a 2.9% decline in the Mining, quarrying and

oil and gas extraction figures. This is the largest single sector in the Northwest

Territories economy.

d. In December 2015, De Beers Canada announced the closure of its Snap Lake

diamond mine.5 The preliminary 2015 GDP estimates will not reflect the full

annualized impact of the closure of the Snap Lake diamond mine.

5. Territorial population growth estimates are low, less than 0.5% between 2015 and 2016.6

Based on these considerations, the Corporations view is that the modest recovery in sales for

2016/17 over 2015/16 is reasonable for the purposes of interim rates for 2016/17. The

Corporation does not believe it is appropriate or reasonable to forecast a return to 2013/14

sales levels for 2016/17 for the purpose of setting interim rates. The best information the

Corporation has available is that 2013/14 had unusually high sales due to a colder winter and

that economic recovery in the NWT will be slow for some time.

3 Available: http://www.nwtchamber.com/sites/default/files/3.%20TAKING%20THE%20PULSE%20-

%20CONFERENCE%20BOARD.pdf 4 GNWT Bureau of Statistics Gross Domestic Product 2015 Preliminary. Available:

http://www.statsnwt.ca/economy/gdp/2016GDP_APR.pdf 5 http://www.cbc.ca/news/canada/north/n-w-t-s-snap-lake-diamond-mine-to-cease-operations-

immediately-1.3350770 6Source: NWT Bureau of Statistics. Available: http://www.statsnwt.ca/population/population-estimates/.

http://www.nwtchamber.com/sites/default/files/3.%20TAKING%20THE%20PULSE%20-%20CONFERENCE%20BOARD.pdfhttp://www.nwtchamber.com/sites/default/files/3.%20TAKING%20THE%20PULSE%20-%20CONFERENCE%20BOARD.pdfhttp://www.statsnwt.ca/economy/gdp/2016GDP_APR.pdfhttp://www.cbc.ca/news/canada/north/n-w-t-s-snap-lake-diamond-mine-to-cease-operations-immediately-1.3350770http://www.cbc.ca/news/canada/north/n-w-t-s-snap-lake-diamond-mine-to-cease-operations-immediately-1.3350770http://www.statsnwt.ca/population/population-estimates/

Thermal Generation Communities

(TGC)

Information Request


Thermal Generation Communities

TGC.NTPC-1


Topic: Major Cost Drivers

Reference: June 30, 2016 Interim Rate Application [Page 4 of 5]

Preamble:

While NTPC has provided a very high level summary (4 bulleted points on page 4 of 5) of key

changes since its 2013/14 Test Year, the TGC desires additional information to assess the

nature of contentious issues and extent to which such items should be included for recovery

through interim rates.

Requests:

a) Please provide a table which shows the major cost drivers (costs greater than +/-

$250,000 or 10%) which contribute to the increase (decrease) in the 2016/17 Revenue

Requirement relative to the most recently approved 2013/2014 Phase 1 GRA in Decision

1-2013 dated January 21, 2013. For clarity, the TGC request is for details at the

functional level for non-fuel O&M costs as well as costs related to capital, deferred costs

and deferral accounts.

b) To the extent possible, please provide the information requested in a) above on a zonal

basis.

c) To the extent one rate zones cost increases contribute to a greater portion of the

projected overall corporate shortfall of $8.157M, please explain why an across-the-board

4.80% interim rate rider is appropriate.

Response:

(a) and (b)

Please refer to BR.NTPC-1(a). For functional level non-fuel O&M costs please attached

Schedules 5.0, 5.1-1, 5.1-2 and 5.1-3 from the 2016/19 GRA.

(c)

Please refer to BR.NTPC-1 (b) and (c)

Revised July 12, 2016

Schedule 5.0

Function

Codes Descriptions

2013/14

Forecast

2013/14

Actual

2014/15

Actual

2015/16

Forecast

2016/17

Forecast

2017/18

Forecast

2018/19

Forecast

Generation 12,582 13,537 15,023 15,239 14,949 15,536 15,754

Hydro Generation

8474 Telecontrol system expense 452 397 363 409 240 244 247

8475 SCADA control centre expense 372 141 167 122 204 207 210

8600 Electrical - operation & maintenance management 386 261 233 265 216 219 221

8601 Hydro generation expense 847 1,074 1,008 1,199 1,060 1,077 1,090

8602 Hydro camp expenses 230 501 494 558 502 513 523

8603 Mechanical - operation & maintenance management 8 14 103 17 25 26 26

8604 Hydro maintenance of powerhouse & structures 340 165 193 149 186 190 193

8606 Hydro maintenance of dams, waterways and reservoirs 75 76 107 99 123 125 127

8607 Hydro maintenance of other 170 173 110 138 150 152 154

8608 Mechanical - Overhaul hydro unit 0 0 0 (63) 0 2 4

8609 Electrical - Overhaul hydro unit 0 (0) 0 0 0 0 0

8618 Mechanical - Maintenance hydro unit 0 13 145 542 465 472 479

8619 Electrical - Maintenance hydro unit 135 174 176 223 98 100 102

8628 Mechanical - Hydro maintenance of plant auxiliaries 0 10 16 16 27 28 28

8629 Electrical - Hydro maintenance of plant auxiliaries 92 85 145 139 116 118 120

Thermal Generation

8468 Thermal Supervisory Systems 70 40 62 91 198 201 204

8677 System control expense 0 0 0 0 0 0 0

8637 Maintenance planning 0 8 124 151 167 169 170

8639 Apprentice Positions - Electricians 12 0 1 0 0 0 0

8640 Thermal operation management 958 914 627 535 651 663 670

8642 Thermal generation expense 3,019 3,755 4,361 4,145 3,932 4,312 4,360

8643 Thermal generation maintenance management 298 188 474 542 640 652 659

8644 Maintenance of th. gen. powerhouse, plant & auxiliaries 2,289 3,267 2,471 2,330 2,267 2,314 2,352

8646 Overhaul thermal generation unit 0 0 0 0 0 0 0

8647 Maintenance costs for emergency genset units 0 20 8 25 24 24 25

8648 Mechanical - Overhaul thermal generation unit 0 0 0 0 0 0 0

8649 Electrical - Overhaul thermal generation unit 0 0 0 0 0 0 0

8657 Thermal generation unit maintenance 2,317 1,892 2,264 2,222 2,163 2,197 2,232

8658 Mechanical - Thermal generation unit maintenance 508 265 575 422 452 465 473

8659 Electrical - Thermal generation unit maintenance 0 52 279 65 57 59 60

8660 LNG offloading 0 0 11 0 0 0 0

8662 Maintenance of LNG plant 0 0 48 5 4 4 4

8668 Mechanical - Maint. of th. gen. powerhouse, plant & auxiliaries 0 0 120 395 390 398 406

8669 Electrical - Maint. of th. gen. powerhouse, plant & auxiliaries 0 0 254 315 282 296 299

8673 Transmission line substation structures & equipment 0 0 1 164 290 293 296

Alternative Generation

8635 Operation and maintenance of alternative energy facilities 0 7 16 10 9 10 10

Residual Heat

8697 Residual heat maintenance 5 46 66 10 10 10 10

Transmission 780 358 1,048 775 720 733 747

8870 Transmission line management 22 5 1 0 0 0 0

8871 Transmission line overhead expense 111 48 79 165 160 162 164

8872 Transmission brushing expense 418 43 640 610 560 571 583

8873 Transmission line substation structures and equipment 230 261 328 0 0 0 0

Distribution 3,407 3,201 3,064 1,318 2,934 2,974 3,014

8810 T&D - Vehicle operations and maintenance 0 210 170 61 179 182 186

8811 T&D - Equipment operations and maintenance 0 59 55 155 110 112 114

8812 T&D lineshop costs 0 61 59 67 94 95 97

8880 Distribution line management 116 129 15 0 0 0 0

8881 Distribution brushing expense 143 46 46 75 150 153 156

8882 Distribution overhead lines 2,598 1,894 1,986 839 2,134 2,160 2,186

8883 Distribution line underground 9 0 1 0 0 0 0

8884 Distribution customer demand meters 16 7 6 0 0 0 0

8885 Distribution line primary equipment 50 30 16 0 0 0 0

8887 Distribution line streetlights 86 124 45 0 43 43 43

8888 Distribution substation expense 12 7 19 0 0 0 0

8889 Distribution line customer meter reading 314 280 271 106 162 163 165

8890 Apprentice linepersons' training 0 0 1 0 10 10 10

8892 Trouble Calls 64 354 374 15 54 55 56

Billing & Customer Accounting 1,408 266 257 490 465 470 475

8886 Distribution line customer service 1,408 266 257 490 465 470 475

General Expense Functions 3,491 3,307 2,899 3,489 2,842 2,893 2,944


2016/19 GENERAL RATE APPLICATION

O&M Expense by Account Code and Function - NTPC

NTPC General Rate Application 2016/19


Schedule 5.0

Function

Codes Descriptions

2013/14

Forecast

2013/14

Actual

2014/15

Actual

2015/16

Forecast

2016/17

Forecast

2017/18

Forecast

2018/19

Forecast



O&M Expense by Account Code and Function - NTPC

8480 Hazardous waste disposal 23 60 109 78 110 112 114

8482 Water Testing 1 2 0 0 0 0 0

8483 Hazardous Materials Cleanup 0 4 0 2 2 2 2

8486 Safety 0 6 6 7 6 6 6

8487 Environmental 349 147 117 81 73 74 76

8710 OPERATIONS - Vehicle operations and maintenance 587 831 575 603 533 543 553

8711 OPERATIONS - Equipment operations and maintenance 352 89 79 124 199 203 207

8717 Housing O&M Expense 239 308 241 335 371 378 384

8719 Building, yard and fence maint. expense 543 663 675 783 901 916 931

8720 Stores warehouse expense 252 199 113 344 33 34 35

8721 Fuel storage facilities 66 11 5 10 17 17 18

8722 Stockkeeper 0 0 50 94 125 126 128

8732 Network Support Operation & Maintenance 1,076 987 928 1,028 473 483 492

Administration Functions 2,764 2,214 2,158 2,060 2,094 2,147 2,189

8730 Administration O&M 2,764 2,214 2,158 2,060 2,094 2,147 2,189

Common Costs 14,699 15,785 17,572 19,527 18,316 18,753 19,035

8138 Distribution related (Billing) 251 59 224 250 268 271 274

8162 Distribution related (CSM maintenance) 27 105 40 60 61 62

8163 Distribution related (Service Desk Management) 113 0 21 153 144 145 147

8803 Distribution related (Customer service) 347 1,072 997 1,373 1,568 1,591 1,609

8880 Distribution line management 105 115 379 363 367 371

8882 Distribution overhead lines 128 241 331 1,925 887 909 921

8890 Apprentice Linepersons' training 72 5 48 52 1 1 1

Corporate 12,596 13,248 13,991 14,183 13,394 13,739 13,948

Regional 1,191 1,030 1,739 1,172 1,632 1,670 1,702

Grand Total 39,130 38,668 42,022 42,899 42,319 43,506 44,157

Common Cost Allocation Formula

Step 1: [Corp Dist cost] x [Zone's share in corporate retail sales]

Step 2: [Regional dist cost] x [Zone's share in regional retail sales]

Step 3: [Other corporate cost] x [Zone's share in corporate sales]

Step 4: [Other regional area cost] x [Zone's share in regional sales]

Step 5: Step 1 + Step 2 + Step 3 + Step 4



Schedule 5.1-1

Function

Codes Descriptions

2013/14

Forecast

2013/14

Actual

2014/15

Actual

2015/16

Forecast

2016/17

Forecast

2017/18

Forecast

2018/19

Forecast

Generation 3,843 4,266 5,478 6,182 5,297 5,392 5,469

Hydro Generation




8601 Hydro generation expense 591 727 704 938 845 855 865



8604 Hydro maintenance of powerhouse & structures 328 146 166 115 161 164 168

8606 Hydro maintenance of dams, waterways and reservoirs 66 68 78 92 105 107 109

8607 Hydro maintenance of other 85 99 43 23 20 20 20

8608 Mechanical - Overhaul hydro unit 0 0 12 0 0 0

8609 Electrical - Overhaul hydro unit (0) 0 0 0 0

8618 Mechanical - Maintenance hydro unit 13 145 542 465 472 479

8619 Electrical - Maintenance hydro unit 103 158 151 219 72 73 75

8628 Mechanical - Hydro maintenance of plant auxiliaries 10 16 16 27 28 28

8629 Electrical - Hydro maintenance of plant auxiliaries 60 52 125 116 82 84 85

Thermal Generation

8468 Thermal Supervisory Systems 3 3 8 11 39 39 40

8677 System control expense 0 0 0 0

8637 Maintenance planning 8 124 151 167 169 170

8639 Apprentice Positions - Electricians 0 1 0 0 0 0

8640 Thermal operation management 346 346 175 118 87 88 89

8642 Thermal generation expense 374 575 1,042 1,393 846 861 872

8643 Thermal generation maintenance management 26 15 55 173 285 288 291

8644 Maintenance of th. gen. powerhouse, plant & auxiliaries 597 940 481 0 0 0 0

8646 Overhaul thermal generation unit

8647 Maintenance costs for emergency genset units 0 0 0 0 0 0

8648 Mechanical - Overhaul thermal generation unit

8649 Electrical - Overhaul thermal generation unit

8657 Thermal generation unit maintenance 136 0 0 0 0 0 0

8658 Mechanical - Thermal generation unit maintenance 1 115 527 343 334 344 350

8659 Electrical - Thermal generation unit maintenance 12 203 31 29 29 30

8660 LNG offloading 0 0 0 0 0

8662 Maintenance of LNG plant 0 0 0 0 0

8668 Mechanical - Maint. of th. gen. powerhouse, plant & auxiliaries 117 383 359 366 373

8669 Electrical - Maint. of th. gen. powerhouse, plant & auxiliaries 0 241 283 266 280 283

8673 Transmission line substation structures & equipment 1 138 185 187 189

Alternative Generation

8635 Operation and maintenance of alternative energy facilities 0 0 0 0 0

Residual Heat

8697 Residual heat maintenance 0 0 0 0 0 0 0

Transmission 432 252 174 92 387 395 402

8870 Transmission line management 19 0 0 0 0 0 0

8871 Transmission line overhead expense 65 25 26 92 107 109 111

8872 Transmission brushing expense 193 29 71 0 280 286 291

8873 Transmission line substation structures and equipment 155 198 77 0 0 0 0

Distribution 798 521 513 206 453 458 464

8810 T&D - Vehicle operations and maintenance 13 23 10 36 37 37

8811 T&D - Equipment operations and maintenance 10 10 25 30 31 31

8812 T&D lineshop costs 0 0 0 0 0 0

8880 Distribution line management 25 0 1 0 0 0 0

8881 Distribution brushing expense 31 3 0 75 40 41 42

8882 Distribution overhead lines 691 434 427 96 347 350 354

8883 Distribution line underground 0 0 0 0 0 0 0

8884 Distribution customer demand meters 2 0 0 0 0 0 0

8885 Distribution line primary equipment 14 2 0 0 0 0 0

8887 Distribution line streetlights 7 2 5 0 0 0 0

8888 Distribution substation expense 4 5 2 0 0 0 0

8889 Distribution line customer meter reading 19 25 18 0 0 0 0

8890 Apprentice linepersons' training 0 0 0 0 0 0

8892 Trouble Calls 4 26 27 0 0 0 0

Billing & Customer Accounting 234 7 6 35 31 31 32

8886 Distribution line customer service 234 7 6 35 31 31 32

General Expense Functions 1,099 1,253 1,116 1,305 810 824 839



O&M Expense by Account Code and Function - Snare Zone



Schedule 5.1-1

Function

Codes Descriptions

2013/14

Forecast

2013/14

Actual

2014/15

Actual

2015/16

Forecast

2016/17

Forecast

2017/18

Forecast

2018/19

Forecast



O&M Expense by Account Code and Function - Snare Zone

8480 Hazardous waste disposal 13 (3) 16 25 66 67 68

8482 Water Testing 1 0 0 0 0 0

8483 Hazardous Materials Cleanup 0 1 0 0 0 0 0

8486 Safety 6 6 7 6 6 6

8487 Environmental 116 39 25 11 20 21 21

8710 OPERATIONS - Vehicle operations and maintenance 71 255 168 145 91 93 94

8711 OPERATIONS - Equipment operations and maintenance 242 70 68 110 99 101 103

8717 Housing O&M Expense 39 40 15 15 19 19 19

8719 Building, yard and fence maint. expense 151 192 228 139 155 158 161

8720 Stores warehouse expense 193 128 48 156 30 30 31

8721 Fuel storage facilities 2 8 5 5 13 13 14

8722 Stockkeeper 50 94 125 126 128

8732 Network Support Operation & Maintenance 272 518 487 598 186 190 194

Administration Functions 1,322 1,076 1,181 1,027 1,168 1,203 1,226

8730 Administration O&M 1,322 1,076 1,181 1,027 1,168 1,203 1,226

Common Costs 7,945 8,224 9,030 9,195 8,825 9,038 9,176

8138 Distribution related (Billing) 33 5 18 20 35 35 36

8162 Distribution related (CSM maintenance) 2 8 3 8 8 8

8163 Distribution related (Service Desk Management) 15 2 12 19 19 19

8803 Distribution related (Customer service) 46 83 79 108 206 208 211

8880 Distribution line management 25 4 52 63 63 64

8882 Distribution overhead lines 35 38 63 182 129 132 133

8890 Apprentice Linepersons' training 26 6 5 0 0 0

Corporate 7,320 7,673 8,182 8,292 7,789 7,983 8,103

Regional 468 399 667 521 576 589 601

Grand Total 15,673 15,599 17,498 18,043 16,970 17,341 17,608

Common Cost Allocation Formula

Step 1: [Corp Dist cost] x [Zone's share in corporate retail sales]

Step 2: [Regional dist cost] x [Zone's share in regional retail sales]

Step 3: [Other corporate cost] x [Zone's share in corporate sales]

Step 4: [Other regional area cost] x [Zone's share in regional sales]

Step 5: Step 1 + Step 2 + Step 3 + Step 4



Schedule 5.1-2

Function

Codes Descriptions

2013/14

Forecast

2013/14

Actual

2014/15

Actual

2015/16

Forecast

2016/17

Forecast

2017/18

Forecast

2018/19

Forecast

Generation 1,217 1,437 1,295 1,452 1,552 1,596 1,620

Hydro Generation




8601 Hydro generation expense 256 346 304 261 215 222 225



8604 Hydro maintenance of powerhouse & structur

Documents

NWT Public Utilities Board (BR) Utilities Board BR.NTPC-1 July 20, 2016 Page 1 of 8 ... employee future benefits deferral account increasing because of a new actuarial study and