nwt public utilities board (br)

NWT Public Utilities Board

(BR)

Information Request

NTPC GRA 2012/13 and 2013/14


BR.NTPC-1

June 8, 2012 Page 1 of 2

TOPIC:

Forecasting Assumptions and Update

PREAMBLE:

The Board wishes to review and assess the general forecasting assumptions used in the test year

forecasts.

REQUEST:

a) Please provide the assumptions used in each test year with respect to the following:

• Salaries and wages escalation for Union;

• Salaries and wages escalation for Non-Union;

• Contractor price escalation-capital;

• Contractor price escalation-non capital;

• Supplies and services escalation; and

• Travel and accommodation escalation Provide support for each of the above

assumptions.

b) If the actual information is available please update the 2012 14 GRA Excel Schedules to

reflect 2011/12 actual information.

RESPONSE:

(a)

In general, the Corporation utilizes both Zero-Based (bottom-up) and Incremental Based

(top-down) budgeting methods as part of its budget process. Budgets are prepared by department

and regional managers and take into account the Corporation’s objectives and strategic initiatives.

Please refer to the Corporation’s forecast assumptions summarized below:

Salaries & Wages – The Corporation applied an assumed labour rate increase to the number of

positions forecasted for the 2012/13 Test Year. The Corporation is currently engaged in contract

negotiations with the Union of Northern Workers (UNW) and is not able to disclose the increase in

labour rates assumed for this GRA. The Corporation is willing to disclose all forecast assumptions

used for salaries and wages once negotiations have been concluded. See also the Corporation’s

response to TGC.NTPC-27(c).

Information Request

NTPC GRA 2012/13 and 2013/14


BR.NTPC-1


Supplies & Services – Please see the comments above regarding NTPC budgeting process.

Specific cost elements within the broad category of supplies and services were either adjusted up

or down based on operational estimates for the 2012/13 fiscal year. The 2012/13 forecast results

were also compared to 2011/12 forecast and the prior three years of actual results as a test of

reasonableness.

Included in this category are contractor services. As such, this treatment was also applied to

forecasting contractor price escalations for non-capital work. Contractor price escalation for

capital work is budgeted directly to the applicable capital job.

The 2013/14 supplies and services forecast was derived by inflating the 2012/13 Test Year

amounts by an assumed inflation factor of 2%.

Travel & Accommodation – Please see the comments above regarding the NTPC budgeting

process. Specific cost elements within the broad category of travel and accommodations were

either adjusted up or down based on operational estimates for the 2012/13 fiscal year. The

2012/13 forecast results were also compared to 2011/12 forecast and the prior three years of

actual results as a test of reasonableness.

The 2013/14 travel and accommodations forecast was derived by inflating the 2012/13 Test Year

amounts by an assumed inflation factor of 1.5%.

(b) NTPC is currently completing its annual audit review with the Office of the Auditor General to

finalize its financial results for 2011/12. As a result, actual results for 2011/12 are not available.

NTPC expects to make 2011/12 financial results public once its Minister has tabled the financial

results with the Legislative Assembly.

Information Request

NTPC GRA 2012/13 and 2013/14


BR.NTPC-3


TOPIC:

O&M Expenses

REFERENCE:

Section 3.2

PREAMBLE:

The Board wishes to examine the pattern of O&M expense changes since the last GRA

with a view to assessing the test year forecasts.

REQUEST:

a) Please expand Table 3.3 to show the 2007/08 actual and 2008/09 to 2011/12

actual information by year. Provide explanations for any material variations from

year to year.

RESPONSE:

(a)

Please see Attachment BR.NTPC-3(a) for the expanded Table 3.3. It is noted that O&M

expenses for 2012/13 and 2013/14 test years adjusted for extraordinary expenses

discussed in the Application (apprenticeship program, increased working hours for plant

operators, insurance premium and communication charges) are $35.96 million and

$36.92 million, respectively.

The 2006/08 GRA forecasts included $0.670 million in this category for the Reserve for

Injuries and Damages and $0.129 million for brushing in this category. These costs are

now tracked as Deferral Accounts.

Please refer to BR.NTPC-4(a), BR.NTPC-5(a) and BR.NTPC-6 for explanations of

material variations from year to year.

Information Request

NTPC GRA 2012/13 and 2013/14


BR.NTPC-3


Attachment BR.NTPC-3(a)

O&M Expenses by Year ($000s)

Operation & Maintenance Expense ($000's)2007/08

Test Year

Variance to 2007/08 Actual

2007/08 Actual

Variance to 2008/09

2008/09 Actual

Variance to 2009/10

2009/10 Actual

Variance to 2010/11

2010/11 Actual

Variance to 2011/12

2011/12 Forecast

Variance to 2012/13

2012/13 Forecast

Variance to 2013/14

2013/14 Forecast

6-year Average Annual Growth

Salaries and Wages 18,273 316 18,589 273 18,862 987 19,849 1,290 21,139 539 21,678 746 22,424 1,068 23,492Non-Production Fuel 745 -81 664 270 934 -89 845 101 946 -54 892 48 940 19 959Supplies and Services 10,676 774 11,451 1,195 12,645 943 13,588 -467 13,121 -219 12,902 -1,089 11,812 236 12,049Travel and Accommodation 2,199 -3 2,196 420 2,617 -472 2,145 73 2,217 161 2,378 -166 2,212 33 2,245

Total O&M Expense 31,893 1,006 32,899 2,158 35,058 1,369 36,427 997 37,424 427 37,850 -462 37,388 1,356 38,744

Less: Corporate Donations 103 -35 68 22 90 -1 89 13 102 19 121 -13 108 2 110

Total O&M Expense for GRA 31,790 1,041 32,831 2,136 34,967 1,370 36,337 984 37,321 408 37,729 -449 37,280 1,354 38,634

Adjustment for RFID, brushing and Extraordinary Expenses 799 1,324 1,718

O&M Expense Adjusted for RFID and Etraordinary Expenses 30,991 35,956 36,916 3.0%

Information Request

NTPC GRA 2012/13 and 2013/14


BR.NTPC-4


TOPIC:

Salaries and Wages

REFERENCE:

Section 3.2.1

PREAMBLE:

The Board wishes to examine the pattern of changes to salaries and wages since the

last GRA with a view to assessing the test year forecasts.

REQUEST:

a) Please provide a schedule of salaries and wages by component showing base

salaries, benefits, incentives or bonus payments, overtime, casual wages and

contract salaries, for 2007/08 GRA forecast, 2007/08 actual, 2008/09 to 2011/12

actual, 2012/13 and 2013/14 forecast, by year. Provide explanations for

significant variances from year to year.

b) Please provide a schedule of salaries and wages by rate zone and Corporate

Head Office, for 2007/08 GRA forecast, 2007/08 actual, 2008/09 to 2011/12

actual, 2012/13 and 2013/14 forecast by year. Provide explanations for


c) Please provide a breakout of employee benefits (Pension, post-employment

benefits, other) for 2007/08 GRA forecast, 2007/08 actual, 2008/09 to 2011/12

actual, 2012/13 and 2013/14 forecast by year. Provide explanations for


d) NTPC states in order to assist in the development and retention of trades people

in high demand positions, NTPC has undertaken a renewed apprenticeship

program adding four new apprentice employees for part of the year resulting in

$0.306 million in increased salaries and wages compared to 2007/08. Please

provide further details of the program (number of employees, subsidy from the

Information Request

NTPC GRA 2012/13 and 2013/14


BR.NTPC-4


Territorial Government if any) and explain how the apprenticeship program fits

into NTPC's succession planning and why the cost of the apprenticeship program

is a prudent cost for rate payers to bear.

e) NTPC states in order to be more responsive to community needs and reliability

issues the Corporation has increased the working hours for 19 plant operators

from part time to full time. This initiative has increased salaries and wages by

$0.471 million since the 2007/08 test year. Please provide any studies or reports

that were carried out which examined and evaluated the costs, benefits and

merits of this initiative.

RESPONSE:

(a) through (c)

As per PUB direction from the 2006/08 GRA, this forecast represents 50% the

Corporation’s total forecast at-risk program.

Please refer to Attachment BR.NTPC-4(a-c) below. The information presented does not

include final year-end manual adjustments. For the purpose of this response, the

Corporation has included At-Risk payments as part of regular salaries. For a summary of

the Corporation’s At-Risk payments please refer to Response TGC.NTPC-45(i) through

(k). As per PUB direction from the 2006/08 GRA, the Corporation’s at-risk forecast

represents 50% of the Corporation’s total forecast at-risk program.

(d)

Please refer to Response TGC.NTPC-27(f).

(e)

Please refer to Response TGC.NTPC-27(g) and (h). No external studies were

undertaken by the Corporation to evaluate working hours for plant operators in isolated

communities. The Corporation undertook an internal evaluation which reviewed the

advantages and disadvantage for three options.

Information Request

NTPC GRA 2012/13 and 2013/14


BR.NTPC-4


These three options are as follows:

1. Status Quo;

2. Increase all plant operator work schedules to 40 hours per week; and

3. Increase plant operator work schedules to 40 hours per week for only those

plants that generated more than 1.5 GWh annually; and increase all other plant

operator work schedules to 30 hours per week.

As a result of its internal review, NTPC pursued option 3 as it addressed community

concerns and the Corporation’s strategic initiatives to:

• Increase and maintain a higher level of working skills at the operator level;

• Increase response time when troubleshooting problems/outages;

• Ability to attract trades staff to these positions;

• Reduced overtime to accomplish the same result; and

• Availability of these resources to provide other services on a lower cost basis (i.e.

work protection, contract oversight, minor maintenance and trouble shooting).

Information Request

NTPC GRA 2012/13 and 2013/14


BR.NTPC-4


Attachment BR.NTPC-4(a-c)

Salaries and Wages by Component 2007/08 – 2013/14 T est Year ($000s)

2007/08 Total

Forecast

Variance to 2007/08 Actual 1

2007/08 Total

Actual

Year over Year

Change 2

2008/09 Total

Actual

Year over Year

Change 3

2009/10 Total

Actual

Year over Year

Change 4

2010/11 Total

Actual

Year over Year

Change 52011/12

Forecast

Year over Year

Change 62012/13

Test Year

Year over Year

Change 72013/14

Test YearSnare ZonePayroll Regular 2,141 1,968 2,490 2,498 2,565 3,197 2,820 2,965 Fringe Benefits 786 630 688 861 879 1,224 1,069 1,137 Payroll Overtime 199 587 480 515 473 363 427 440 Casual Payroll Regular 26 45 54 40 32 29 37 38 Casual Payroll Overtime - 7 15 6 6 2 7 7

Sub-Total 3,152 85 3,237 490 3,727 193 3,920 35 3,955 860 4,815 (455) 4,360 227 4,587 2.7% 15.1% 5.2% 0.9% 21.7% -9.4% 5.2%

Taltson ZonePayroll Regular 950 861 1,019 1,034 1,055 1,026 1,217 1,314 Fringe Benefits 360 301 321 382 361 385 488 538 Payroll Overtime 16 153 178 176 253 228 166 171 Contract Labour 22 21 28 15 20 - 20 21 Casual Payroll Regular 13 19 39 5 5 4 17 18 Casual Payroll Overtime 1 3 17 - - - 1 1

Sub-Total 1,362 (4) 1,358 244 1,602 10 1,612 82 1,694 (51) 1,643 266 1,909 154 2,063 -0.3% 18.0% 0.6% 5.1% -3.0% 16.2% 8.1%

Thermal ZonePayroll Regular 4,323 3,663 3,485 3,530 3,753 4,387 4,355 4,607 Fringe Benefits 1,930 1,527 1,234 1,487 1,623 1,681 1,892 2,031 Payroll Overtime 519 959 753 852 1,052 944 789 813 Casual Payroll Regular 185 227 270 218 233 272 310 320 Casual Payroll Overtime 17 53 81 56 63 54 61 63 Contract Labour - 26 - - - - - -

Sub-Total 6,974 (519) 6,455 (632) 5,823 320 6,143 581 6,724 614 7,338 69 7,407 427 7,834 -7.4% -9.8% 5.5% 9.5% 9.1% 0.9% 5.8%

Information Request

NTPC GRA 2012/13 and 2013/14


BR.NTPC-4


Attachment BR.NTPC-4(a-c) Con’t

Salaries and Wages by Component 2007/08 – 2013/14 T est Year ($000s)

Notes:

1. Overall variance of 2007/08 forecast with actual amounts are consistent with expected wage rate increases. More salaries in the Snare/Thermal zones were charged to head

office and regional offices

2. Overall variance from 2007/08 actual to 2008/09 actual is consistent with expected wage rate increases. Variances between zones were due to transfers of positions.

3. Overall variance from 2008/09 to 2009/10 is consistent with expected wage rate increases.

4. Overall variance from 2009/10 to 2010/11 is consistent with expected wage rate increases. Variances between zones were due to transfers of positions.

5. Overall variance from 2010/11 to 2011/12 forecast is consistent with expected wage rate increases. Variances between zones were due to transfers of positions.

6. Overall variances from 2011/12 forecast to 2012/13 forecast and from 2010/11 actual to 2012/13 test year are consistent with expected wage rate increases. Variances

between zones were due to transfers of positions. 2012/13 included increased plant hours and additional apprenticeship positions as discussed in TGC.NTPC-27(f) and (g).

7. Overall variances from 2012/13 and 2013/14 are consistent with expected wage rate increases. Variances between zones were due to transfers of positions. 2013/14 included

additional apprenticeship positions as discussed in TGC.NTPC-27(f).

2007/08 Total

Forecast

Variance to 2007/08 Actual 1

2007/08 Total

Actual

Year over Year

Change 2

2008/09 Total

Actual

Year over Year

Change 3

2009/10 Total

Actual

Year over Year

Change 4

2010/11 Total

Actual

Year over Year

Change 52011/12

Forecast

Year over Year

Change 62012/13

Test Year

Year over Year

Change 72013/14

Test YearHead Office and Regional OfficePayroll Regular 4,827 5,569 5,740 6,044 6,334 5,489 6,223 6,407 Fringe Benefits 1,682 1,654 1,521 1,600 2,116 2,118 2,298 2,367 Payroll Overtime 224 257 324 267 259 216 161 166 Casual Payroll Regular 51 59 121 63 84 59 64 66 Casual Payroll Overtime 1 - 4 - 9 - 2 2

Sub-Total 6,785 754 7,539 171 7,710 264 7,974 828 8,802 (920) 7,882 866 8,748 260 9,008 11.1% 2.3% 3.4% 10.4% -10.5% 11.0% 3.0%

NTPC TotalPayroll Regular 12,242 12,061 12,734 13,107 13,707 14,099 14,615 15,293 Fringe Benefits 4,757 4,112 3,764 4,329 4,979 5,408 5,747 6,073 Payroll Overtime 958 1,956 1,735 1,810 2,037 1,751 1,543 1,590 Casual Payroll Regular 275 350 484 326 354 364 428 442 Casual Payroll Overtime 19 63 117 62 78 56 71 73 Contract Labour 22 47 28 15 20 - 20 21

NTPC Total 18,273 316 18,589 273 18,862 787 19,649 1,526 21,175 503 21,678 746 22,424 1,068 23,492 1.7% 1.5% 4.2% 7.8% 2.4% 3.4% 4.8%

Information Request

NTPC GRA 2012/13 and 2013/14


BR.NTPC-5


TOPIC:

Supplies and Services

REFERENCE:

Section 3.2.3

PREAMBLE:

NTPC states absent these notable items (insurance premiums, communication charges),

the increase in supplies and services since 2007/08 is $1.442 million or 2.3% average

annual growth per year. This residual growth largely reflects inflation.

REQUEST:

a) Please provide a breakout of supplies and services by prime account for 2007/08

GRA forecast, 2007/08 actual, 2008/09 to 2011/12 actual, 2012/13 and 2013/14

forecast by year. Provide explanations for significant variances from year to year.

b) NTPC indicates communication costs have increased ($0.279million) since the

2006/08 GRA as NTPC developed remote diesel SCADA systems allowing for

remote diesel plant monitoring from NTPC’s Central Control facility. Please

identify the specific benefits resulting from these communication cost increases.

RESPONSE:

(a)

Please see Attachment BR.NTPC-5(a) below for a breakout of supplies and services by

prime account.

• 2007/08 actual over forecast variance explanation: Maintenance costs were

higher than budgeted in 2007/08 due to more unforeseen repairs.

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NTPC GRA 2012/13 and 2013/14


BR.NTPC-5


• 2008/09 variance explanation: Increased use of contractors for line

maintenance, equipment maintenance, and other equipment maintenance in

2008/09 compared to 2007/08. Equipment maintenance and camp costs

accounted for approximately $0.8 million of the increase. Additional contract

linemen used accounted for approximately $0.2 million.

• 2009/10 variance explanation: 2009/10 Administrative costs (miscellaneous

expense) included approximately $0.6 million of corrections to previous year

expenses, which was recorded in miscellaneous expenses. 2009/10

miscellaneous expenses also included the cost of denial of previously claimed

GST tax credits of approximately $0.5 million.

• 2010/11 variance explanation: As explained above, there were approximately

$1.1 million in "miscellaneous expenses" in 2009/10 that were non-recurring in

nature. In 2010/11, miscellaneous expenses included $0.075 million related to a

claim settlement and a $0.3 million adjustment related to the reversal of

previously recognized rider revenue.

Forecast years significant variances have been discussed in the Application.

(b)

Key Benefits of SCADA related to NTPC include:

• Real time monitoring, and Asset Management of Hydro and Thermal based

communities.

o Increases operational efficiency to manage the generation, transmission

and distribution of the electrical system from the central control room for

North/South Slave Hydro regions.

o Provides immediate visual performance of system operation, for Hydro

and Thermal based generation regions.

o Provides immediate response of all events, alarms and automated outage

reporting by email to staff.

o Real time information provides staff with the tools to assist in fault

analysis, optimize performance and track reliability.

Information Request

NTPC GRA 2012/13 and 2013/14


BR.NTPC-5


o SCADA complements the direction of the company in terms of Asset

Management effectively by tracking operational data.

o Web based access for multi-departmental requests for real time

operational data for reporting.

• Data collection for analysis and reporting functions:

o High level reporting of data for operations, for both Hydro and Thermal

Based communities.

o Access to detailed daily event reports provides analysis for fault analysis

and maintenance planning.

o Centralized alarm reporting and data collection.

o Web based access for enterprise functions for financial, engineering and

operational requirements.

o Historical data collection facilitates load forecasting, minimum and peak

loads data.

• Spin off incentives:

o SCADA provides the mechanism to improve operations of the plants over

time by identifying key aspects and to incorporate those future projects

into the planning and Asset Management of these sites.

o Key Aspects that can be realized with future projects.

o Optimizing fuel efficiencies, when fuel measurement equipment is

installed and combined with economic dispatch (PLC) based automation.

o Data for CMMS - computer maintenance management system and/or

predictive maintenance.

• Data modeling for alternative energy initiatives combined with diesel generation.

Information Request

NTPC GRA 2012/13 and 2013/14


BR.NTPC-5



Supplies and Services Expenses by Prime Account ($000s)

Note:

The 2007/08 GRA forecast included $0.670 million of RFID provision and $0.129 million for brushing - these have been removed in above analysis. The actual amounts spent on

brushing each year have also been removed for consistency. In future years, these two amounts are budgeted in amortization of deferred charges.

Description

2007/08 Total

Forecast


2007/08 Total

Actuals

Year over Year

Change

2008/09 Total

Actuals

Year over Year

Change

2009/10 Total

Actuals

Year over Year

Change

2010/11 Total

Actuals

Year over Year

Change

2011/12 Total

Forecast

Year over Year

Change

2012/13 Total

Forecast

Year over Year

Change

2013/14 Total

Forecast 2,430 374 2,804 202 3,006 (147) 2,859 (67) 2,792 (221) 2,571 81 2,652 53 2,7054,605 434 5,039 (167) 4,871 1,569 6,440 (984) 5,456 223 5,680 (85) 5,595 112 5,7072,843 294 3,137 1,517 4,654 (562) 4,092 340 4,432 (700) 3,732 (167) 3,565 71 3,6369,877 1,102 10,980 1,551 12,531 860 13,391 (711) 12,680 (697) 11,983 (171) 11,812 236 12,049Total Supplies and Services

MaterialsAdministrationContractors and Consultants

Information Request

NTPC GRA 2012/13 and 2013/14


BR.NTPC-6


TOPIC:

Travel and Accommodation

REFERENCE:

Section 3.2.4

PREAMBLE:

Travel and accommodation expense includes all the travel, accommodation and meal

costs associated with staff travel for operational and professional development

purposes.

REQUEST:

a) Please provide a breakout of travel and accommodation by prime account for

2007/08 GRA forecast, 2007/08 actual, 2008/09 to 2011/12 actual, 2012/13 and

2013/14 forecast by year. Provide explanations for significant variances from

year to year.

RESPONSE:

(a)

Please see Attachment BR.NTPC-6(a) below for a breakout of travel and

accommodation by prime account. Explanations for significant variances are provided

below:

• 2008/09 variance explanation: There were three permanent positions

previously staffed in the Thermal region that were filled out of other offices on a

fly-in, fly-out basis causing additional travel costs.

• 2009/10 variance explanation: There was a decrease in positions filled in other

offices reducing the need for travel in 2009/10.

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NTPC GRA 2012/13 and 2013/14


BR.NTPC-6


• 2010/11 variance explanation: The net increase in 2010/11 over 2009/10 was

due to a reduction in travel allocated to capital.

Significant variances in forecast years have been discussed in the Application. NTPC

has been able to maintain lower travel and accommodation costs largely through

increased telecommunication and telecontrol technology designed to monitor and control

isolated generating plants.

Information Request

NTPC GRA 2012/13 and 2013/14


BR.NTPC-6



Travel and Accommodations Expenses by Prime Account ($000s)

Description

2007/08 Total

Forecast


2007/08 Total

Actuals

Year over Year

Change

2008/09 Total

Actuals

Year over Year

Change

2009/10 Total

Actuals

Year over Year

Change

2010/11 Total

Actuals

Year over Year

Change

2011/12 Total

Forecast

Year over Year

Change

2012/13 Total

Forecast

Year over Year

Change

2013/14 Total

Forecast Travel 1,392 1,315 1,596 1,150 1,293 1,377 1,169 1,187Accommodation 396 403 477 410 423 367 390 396Meals 309 285 340 280 315 293 416 422Medical 102 194 204 305 187 342 236 240

2,199 (3) 2,196 420 2,617 (472) 2,145 73 2,217 161 2,378 (166) 2,212 33 2,245Total Travel and Accommodation

Information Request

NTPC GRA 2012/13 and 2013/14


BR.NTPC-7


TOPIC:

Return

REFERENCE:

Section 3.5, Schedule 3.6, 3.7

PREAMBLE:

The Board wishes to test the methods and assumptions used in NTPC's return

calculations.

REQUEST:

a) Please reconcile the common equity, long term debt and capital lease obligation

balances shown in Schedule 3.6 for 2010/11 with the corresponding balances in

the financial statements for 2010/11. Provide explanations for each reconciling

item.

b) Please provide a Schedule for each of the years ended 2009/10, 2010/11,

2011/12, 2012/13 and 2013/14 showing for each outstanding debt instrument the

principal amount, term, interest rate, sinking fund investment, sinking fund

earnings, financing cost and financing cost amortization. Show the calculation of

the mid-year embedded cost of debt from this schedule. The embedded cost of

debt calculation should be reconciled to the embedded cost of debt shown in

Schedule 3.7.

c) NTPC indicates during the 2012/13 test year the Corporation expects to issue

one long term debt debenture, estimated at $25 million. Please provide the term

and forecast cost rate for the new issue. Provide the basis on which the forecast

cost of new debt was determined, including the forecast cost rate for long

Canada bonds, applicable corporate spreads for NTPC and any relevant

supporting evidence.

Information Request

NTPC GRA 2012/13 and 2013/14


BR.NTPC-7


RESPONSE:

(a)

Please refer to Table 1 below. There is a $0.480 million variance for the March 31, 2011

equity balance. The Corporation will provide revised schedules with the corrected equity

opening balance before the hearing.

Information Request

NTPC GRA 2012/13 and 2013/14


BR.NTPC-7


Table 1:

Capitalization Reconciliation ($000s)

2011 Ending Balance

Common Equity2012/14 GRA 107,5702011 Financial Statements 105,664

Difference 1,906

Reconciling Items:Accumulated Other Comprehsive Income included in Finanical Statements (521)

482Deficit from unregulated operations included in Finanical Statements 1,465

1,426Variance 480

Long-Term Debt2012/14 GRA 183,3672011 Financial Statements 146,783

Difference 36,584

Reconciling Items:(19,953)

1,49516,31638,72636,584

Capital Lease Obligation2012/14 GRA 20,4422011 Financial Statements 1,811

Difference 18,631

Reconciling Items:18,756

Current portion of Net Lease Obligation (125)18,631

Loan Receivable from the Dogrib Power Corporation

Transition Adjustment on adoption of financial instrument standards in the 2008 Financial Statements

Unregulated debt (NTEC) included in Financial StatementsUnamortized premium, discount and issuance costs included in Financial StatementsCurrent portion of Long-term debt included in Financial StatementsSinking Fund Investments included in Financial Statements

Information Request

NTPC GRA 2012/13 and 2013/14


BR.NTPC-7


(b)

Please refer to Attachment BR.NTPC-7(b) 1 - 6 below. The calculation of forecast

sinking fund income for each debenture is for illustrative purposes only. The Corporation

forecasts sinking fund on an aggregate basis and the forecast income was prorated to

each debenture. Aggregate interest expense is calculated in accordance with PUB

Decision 13-2007 and the aggregate weighted average cost of debt was used to

calculate the interest expense for each debenture.

(c)

The Corporation has pursued a policy since its inception of funding capital projects

through a combination of surplus cash flow and short-term debt. At various times when

market conditions have been favorable, short-term debt has been converted to long-term

debt by issuing a privately placed debenture. This practice has been supported by the

Corporation’s customers and the NWT Public Utilities Board.

The Corporation is consulting with its financial advisors on the timing of a debt issue.

The $25 million debt is forecast to have a 30 year term and uses a rate of 4.29%. The

rate is based on long Canada yields at the end of January 2012 plus a credit spread

between 1.50-1.65%. Current economic forecasts predict the long Canada yields should

remain below the 3% range for the remainder of the calendar year. The Corporation is in

a good position to access longer term debt which will allow it to match the term of the

debt to the long asset life. The Corporation should, with the GNWT guarantee, be able to

borrow with a spread over long Canada bonds of not more than 200 basis points

(1/100th of 1% = 1 bp) depending on the repayment structure.

Similar to past practice and in accordance with Section 67(1) of the Public Utilities Act,

the Corporation will file an application with the Board for this debt issuance.

Information Request

NTPC GRA 2012/13 and 2013/14


BR.NTPC-7


Attachment BR.NTPC-7(b) – 1

2008/09 Actual Long-Term Debt Continuity Schedule ( $000s)

Line Loan Number 1 2 3 4 5 6 7 8 9No. Loan Amount 20,000$ 15,000$ 20,000$ 8,700$ 10,000$ 20,000$ 25,000$ 15,000$ 25,000$ TOTAL1 Interest Rate 11.000% 11.125% 10.750% 8.41% 6.330% 6.420% 5.955% 5.000% 5.443% ALL2 Issue Date 9/Mar/89 6/Jun/91 28/May/92 27/Feb/96 27/Oct/98 18/Dec/0 2 15/Dec/04 16/Dec/05 1/Aug/08 LOANS

3 Opening Balance 20,000 15,000 20,000 8,700 10,000 16,667 25,000 15,000 130,3674 Issue 25,000 25,0005 Repayment 20,000 667 20,6676 Closing Balance [L3+L4-L5] 0 15,000 20,000 8,700 10,000 16,000 25,000 15,000 25,000 134,700

7 Mid-Year Debt Balance (MAD) [(L3+L6)/2] 10,000 15,000 20,000 8,700 10,000 16,334 25,000 15,000 12,500 132,534

8 Sinking Fund9 Opening Balance 20,129 10,801 12,677 584 1,734 45,92410 Closing Balance 0 11,501 13,652 742 2,059 27,95411 Mid Year Balance (SFI) [(L9+L10)/2] 10,064 11,151 13,164 663 1,896 36,939

12 DEBT FINANCING COSTS13 Beginning Financing Costs O/S 7 30 22 33 57 1,040 166 98 1,45214 Additions 146 14615 Less Amortization 7 9 9 3 6 74 6 6 5 12516 Ending Financing Costs O/S [L13+L14-L15] 0 20 12 30 51 965 160 92 141 1,473

17 Average Financing Costs (UFC) [(L13+L16)/2] 4 25 17 32 54 1,002 163 95 71 1,462

18 AVERAGE PROCEEDS [L7-L11-L17] -68 3,824 6,819 8,005 8,049 15,331 24,837 14,905 12,429 94,132

INTEREST & AMORTIZATION OF FINANCING COSTS19 Interest Expense Amount (I) = (L3*L1+L6*L1)/2 1,100 1,669 2,150 732 633 1,049 1,489 750 680 10,25120 Less: Interest Revenue Amount (SFE) (747) (827) (977) (49) (141) (2,740)21 Amortization of Finance Costs (AFC) 7 9 9 3 6 74 6 6 5 12522 Total Interest and Amortization 360 851 1,182 685 498 1,123 1,495 756 685 7,636

EFFECTIVE COST OF LONG TERM DEBT -531.48% 22.25% 17.34% 8.56% 6.19% 7.32% 6.02% 5.07% 5.51% 8.11%23 (I+AFC-SFE)/(MAD - UFC - SFI)

Information Request

NTPC GRA 2012/13 and 2013/14


BR.NTPC-7




Line Loan Number 1 2 3 4 5 6 7 8No. Loan Amount 15,000$ 20,000$ 8,700$ 10,000$ 20,000$ 25,000$ 15,000$ 25,000$ TOTAL1 Interest Rate 11.125% 10.750% 8.41% 6.330% 6.420% 5.955% 5.000% 5.443% ALL2 Issue Date 6/Jun/91 28/May/92 27/Feb/96 27/Oct/98 18/Dec/02 15/Dec/ 04 16/Dec/05 1/Aug/08 LOANS

3 Opening Balance 15,000 20,000 8,700 10,000 16,000 25,000 15,000 25,000 134,7004 Issue 05 Repayment 667 6676 Closing Balance [L3+L4-L5] 15,000 20,000 8,700 10,000 15,333 25,000 15,000 25,000 134,033

7 Mid-Year Debt Balance (MAD) [(L3+L6)/2] 15,000 20,00 0 8,700 10,000 15,667 25,000 15,000 25,000 134,367

8 Sinking Fund9 Opening Balance 11,501 13,652 742 2,059 27,95410 Closing Balance 13,972 16,714 1,012 2,670 34,36811 Mid Year Balance (SFI) [(L9+L10)/2] 12,737 15,183 87 7 2,365 31,161

12 DEBT FINANCING COSTS13 Beginning Financing Costs O/S 20 12 30 51 965 160 92 141 1,47314 Additions 015 Less Amortization 9 6 2 5 72 6 6 7 11416 Ending Financing Costs O/S [L13+L14-L15] 11 6 28 46 893 154 86 134 1,359

17 Average Financing Costs (UFC) [(L13+L16)/2] 16 9 29 49 929 157 89 137 1,416

18 AVERAGE PROCEEDS [L7-L11-L17] 2,248 4,808 7,794 7,587 1 4,737 24,843 14,911 24,863 101,790

INTEREST & AMORTIZATION OF FINANCING COSTS19 Interest Expense Amount (I) = (L3*L1+L6*L1)/2 1,669 2,150 732 633 1,006 1,489 750 1,361 9,78920 Less: Interest Revenue Amount (SFE) (917) (1,097) (66) (175) (2,256)21 Amortization of Finance Costs (AFC) 9 6 2 5 72 6 6 7 11422 Total Interest and Amortization 761 1,059 667 463 1,078 1,495 756 1,368 7,647

EFFECTIVE COST OF LONG TERM DEBT 33.86% 22.02% 8.56% 6.10% 7.32% 6.02% 5.07% 5.50% 7.51%23 (I+AFC-SFE)/(MAD - UFC - SFI)

Information Request

NTPC GRA 2012/13 and 2013/14


BR.NTPC-7




Line Loan Number 1 2 3 4 5 6 7 8 9No. Loan Amount 15,000$ 20,000$ 8,700$ 10,000$ 20,000$ 25,000$ 15,000$ 25,000$ 50,000$ TOTAL1 Interest Rate 11.125% 10.750% 8.41% 6.330% 6.420% 5.955% 5.000% 5.443% 5.160% ALL2 Issue Date 6/Jun/91 28/May/92 27/Feb/96 27/Oct/98 18/Dec/02 15/Dec/ 04 16/Dec/05 1/Aug/08 13/Aug/10 LOANS

3 Opening Balance 15,000 20,000 8,700 10,000 15,333 25,000 15,000 25,000 0 134,0334 Issue 50,000 50,0005 Repayment 667 6676 Closing Balance [L3+L4-L5] 15,000 20,000 8,700 10,000 14,666 25,000 15,000 25,000 50,000 183,366

7 Mid-Year Debt Balance (MAD) [(L3+L6)/2] 15,000 20,00 0 8,700 10,000 15,000 25,000 15,000 25,000 25,000 158,700

8 Sinking Fund9 Opening Balance 13,972 16,714 1,012 2,670 34,36810 Closing Balance 15,592 18,713 1,244 3,177 38,72611 Mid Year Balance (SFI) [(L9+L10)/2] 14,782 17,713 1, 128 2,924 36,547

12 DEBT FINANCING COSTS13 Beginning Financing Costs O/S 11 6 28 46 893 154 86 134 1,35914 Additions 249 24915 Less Amortization 9 3 2 5 69 6 6 7 6 11416 Ending Financing Costs O/S [L13+L14-L15] 2 3 26 41 824 147 81 127 244 1,494

17 Average Financing Costs (UFC) [(L13+L16)/2] 6 5 27 44 8 58 151 83 130 122 1,426

18 AVERAGE PROCEEDS [L7-L11-L17] 212 2,282 7,545 7,033 14, 141 24,849 14,917 24,870 24,878 120,726

INTEREST & AMORTIZATION OF FINANCING COSTS19 Interest Expense Amount (I) = (L3*L1+L6*L1)/2 1,669 2,150 732 633 963 1,489 750 1,361 1,290 11,036 20 Less: Interest Revenue Amount (SFE) (1,274) (1,528) (102) (260) (3,163)21 Amortization of Finance Costs (AFC) 9 3 2 5 69 6 6 7 6 11422 Total Interest and Amortization 405 625 632 379 1,032 1,495 756 1,368 1,296 7,987

EFFECTIVE COST OF LONG TERM DEBT 191.29% 27.38% 8.37% 5.39% 7.30% 6.02% 5.07% 5.50% 5.21% 6.62%23 (I+AFC-SFE)/(MAD - UFC - SFI)

Information Request

NTPC GRA 2012/13 and 2013/14


BR.NTPC-7



2011/12 Forecast Long-Term Debt Continuity Schedule ($000s)

Line Loan Number 1 2 3 4 5 6 7 8 9No. Loan Amount 15,000$ 20,000$ 8,700$ 10,000$ 20,000$ 25,000$ 15,000$ 25,000$ 50,000$ TOTAL1 Interest Rate 11.125% 10.750% 8.41% 6.330% 6.420% 5.955% 5.000% 5.443% 5.160% ALL2 Issue Date 6/Jun/91 28/May/92 27/Feb/96 27/Oct/98 18/Dec/02 15/Dec/ 04 16/Dec/05 1/Aug/08 13/Aug/10 LOANS

3 Opening Balance 15,000 20,000 8,700 10,000 14,666 25,000 15,000 25,000 50,000 183,3664 Issue 05 Repayment 15,000 667 15,6676 Closing Balance [L3+L4-L5] 0 20,000 8,700 10,000 14,000 25,000 15,000 25,000 50,000 167,700


8 Sinking Fund9 Opening Balance 15,592 18,713 1,244 3,177 38,72610 Closing Balance 0 20,000 1,665 4,253 25,91811 Mid Year Balance (SFI) [(L9+L10)/2] 7,796 19,357 1,4 54 3,715 32,322

12 DEBT FINANCING COSTS13 Beginning Financing Costs O/S 2 3 26 41 824 147 81 127 244 1,49414 Additions 015 Less Amortization 2 3 2 5 66 6 6 7 8 10616 Ending Financing Costs O/S [L13+L14-L15] 0 0 25 35 757 141 75 119 235 1,388


18 AVERAGE PROCEEDS [L7-L11-L17] -297 642 7,220 6,247 13, 542 24,856 14,922 24,877 49,760 141,770

INTEREST & AMORTIZATION OF FINANCING COSTS19 Interest Expense Amount (I) = (L3*L1+L6*L1)/2 834 2,150 732 633 920 1,489 750 1,361 2,580 11,449 20 Less: Interest Revenue Amount (SFE) (299) (743) (56) (143) (1,240)21 Amortization of Finance Costs (AFC) 2 3 2 5 66 6 6 7 8 10622 Total Interest and Amortization 537 1,410 678 496 987 1,495 756 1,368 2,588 10,315

EFFECTIVE COST OF LONG TERM DEBT -180.81% 219.81% 9.39% 7.94% 7.29% 6.01% 5.06% 5.50% 5.20% 7.28%23 (I+AFC-SFE)/(MAD - UFC - SFI)

Information Request

NTPC GRA 2012/13 and 2013/14


BR.NTPC-7




Line Loan Number 1 2 3 4 5 6 7 8 9No. Loan Amount 20,000$ 8,700$ 10,000$ 20,000$ 25,000$ 15,000$ 25,000$ 50,000$ 25,000$ TOTAL1 Interest Rate 10.750% 8.41% 6.330% 6.420% 5.955% 5.000% 5.443% 5.160% 4.290% ALL2 Issue Date 28/May/92 27/Feb/96 27/Oct/98 18/Dec/02 15/Dec/04 16/Dec /05 1/Aug/08 13/Aug/10 1/Apr/12 LOANS

3 Opening Balance 20,000 8,700 10,000 14,000 25,000 15,000 25,000 50,000 0 167,7004 Issue 25,000 25,0005 Repayment 20,000 667 799 21,4666 Closing Balance [L3+L4-L5] 0 8,700 10,000 13,333 25,000 15,000 25,000 49,201 25,000 171,234


8 Sinking Fund9 Opening Balance 20,000 1,665 4,253 25,91810 Closing Balance 0 1,855 4,738 6,59211 Mid Year Balance (SFI) [(L9+L10)/2] 10,000 1,760 4,4 95 16,255

12 DEBT FINANCING COSTS13 Beginning Financing Costs O/S 0 25 35 757 141 75 119 235 0 1,38814 Additions 153 15315 Less Amortization 0 2 5 64 6 6 7 8 4 10216 Ending Financing Costs O/S [L13+L14-L15] 0 23 30 694 135 69 112 227 149 1,438


18 AVERAGE PROCEEDS [L7-L11-L17] 0 6,917 5,472 12,941 24,8 62 14,928 24,884 49,369 12,426 151,799

INTEREST & AMORTIZATION OF FINANCING COSTS19 Interest Expense Amount (I) = (L3*L1+L6*L1)/2 1,075 732 633 877 1,489 750 1,361 2,559 536 10,012 20 Less: Interest Revenue Amount (SFE) (146) (26) (66) (237)21 Amortization of Finance Costs (AFC) 0 2 5 64 6 6 7 8 4 10222 Total Interest and Amortization 929 708 573 941 1,495 756 1,368 2,568 540 9,878

EFFECTIVE COST OF LONG TERM DEBT 0.00% 10.23% 10.47% 7.27% 6.01% 5.06% 5.50% 5.20% 4.35% 6.51%23 (I+AFC-SFE)/(MAD - UFC - SFI)

Information Request

NTPC GRA 2012/13 and 2013/14


BR.NTPC-7

June 8, 2012 Page 10 of 10



Line Loan Number 1 2 3 4 5 6 7 8No. Loan Amount 8,700$ 10,000$ 20,000$ 25,000$ 15,000$ 25,000$ 50,000$ 25,000$ TOTAL1 Interest Rate 8.41% 6.330% 6.420% 5.955% 5.000% 5.443% 5.160% 4.290% ALL2 Issue Date 27/Feb/96 27/Oct/98 18/Dec/02 15/Dec/04 16/Dec/05 1/Aug/ 08 13/Aug/10 1/Apr/12 LOANS

3 Opening Balance 8,700 10,000 13,333 25,000 15,000 25,000 49,201 25,000 171,2344 Issue 05 Repayment 667 840 1,5076 Closing Balance [L3+L4-L5] 8,700 10,000 12,666 25,000 15,000 25,000 48,361 25,000 169,727

7 Mid-Year Debt Balance (MAD) [(L3+L6)/2] 8,700 10,000 13,000 25,000 15,000 25,000 48,781 25,000 170,480

8 Sinking Fund9 Opening Balance 1,855 4,738 6,59210 Closing Balance 2,025 5,173 7,19911 Mid Year Balance (SFI) [(L9+L10)/2] 1,940 4,956 6,896

12 DEBT FINANCING COSTS13 Beginning Financing Costs O/S 23 30 694 135 69 112 227 149 1,43814 Additions 015 Less Amortization 2 5 61 6 6 7 8 8 10316 Ending Financing Costs O/S [L13+L14-L15] 21 25 633 129 64 105 219 141 1,335

17 Average Financing Costs (UFC) [(L13+L16)/2] 22 27 663 132 67 108 223 145 1,387

18 AVERAGE PROCEEDS [L7-L11-L17] 6,738 5,017 12,337 24,86 8 14,933 24,892 48,558 24,855 162,198

INTEREST & AMORTIZATION OF FINANCING COSTS19 Interest Expense Amount (I) = (L3*L1+L6*L1)/2 732 633 835 1,489 750 1,361 2,517 1,073 9,388 20 Less: Interest Revenue Amount (SFE) (47) (121) (168)21 Amortization of Finance Costs (AFC) 2 5 61 6 6 7 8 8 10322 Total Interest and Amortization 686 518 896 1,495 756 1,368 2,525 1,080 9,324

EFFECTIVE COST OF LONG TERM DEBT 10.18% 10.32% 7.26% 6.01% 5.06% 5.50% 5.20% 4.35% 5.75%23 (I+AFC-SFE)/(MAD - UFC - SFI)

Information Request

NTPC GRA 2012/13 and 2013/14


BR.NTPC-8


TOPIC:

Return

REFERENCE:

Section 3.5, Schedule 3.6

PREAMBLE:

NTPC states it is proposing to finance the entire CWIP with long term debt. As a result it

appears that the actual debt equity ratio in the corporate books would be higher than the

57%:43% shown for regulatory purposes as financing rate base. In previous applications

the debt equity ratio for regulatory purposes and as per the corporate books was about

the same. The difference, in this case, arises due to NTPC's decision to deem CWIP to

be 100% financed by debt.

REQUEST:

a) Please confirm the proposed change in how CWIP and rate base are to be

financed would result in the Corporate debt equity ratio being higher than the

regulatory debt equity ratio. If confirmed please discuss the impact of the change

on the Corporation's financial risk.

b) Since NTPC states the first year for IFRS reporting is 2012/13, [Page 5-6] please

indicate the last date on which AFUDC will cease to apply and the Corporation

would transition to IDC.

c) Please provide a CWIP continuity schedule for each of the years 2009/10,

2010/11 2011/12, 2012/13 and 2013/14 showing, by project, opening CWIP, cost

of additions before carrying costs, AFUDC or IDC, transfers to rate base and

ending CWIP. Please reconcile the CWIP balances for 2011/12, 2012/13 and

2013/14 with the corresponding balances shown in Schedule 3.5.

d) At Page 3-15 NTPC states, with the transition to IFRS, NTPC is no longer able to

charge capital projects a traditional Interest During Construction (“IDC”) rate

Information Request

NTPC GRA 2012/13 and 2013/14


BR.NTPC-8


using regulatory Allowance Funds Used During Construction (“AFUDC”)

concepts based on the average cost of capital (debt plus equity). Discuss the

pros and cons of continuing to use AFUDC for regulatory purposes?

RESPONSE:

(a)

Confirmed. The overall corporate debt-equity ratio would be higher than the debt-equity

ratio used for regulatory purposes. The financial risk to the Corporation should be

minimal as this concept is being applied to the majority of electric utilities in Canada

which comply with IFRS. Rating agencies and bond investors should be aware of the

transition and apply the same metrics to all companies. Also as demonstrated in the

Corporation’s response to BR.NTPC-4(f) of the Interim Rate Application the dollar impact

is $0.020 million in the 2013/14 Test Year.

(b)

In this Application the last date for traditional AFUDC applied to assets under

construction is March 31, 2012.

(c)

Please refer to the excel file Attachment BR.NTPC-8(c).

(d)

The change from a traditional AFUDC rate which uses the average cost of capital to the

interest only method has a greater financial impact to companies with a larger disparity

between cost of debt and cost of equity (particularly where the cost of equity includes

income taxes). Generally speaking equity requires a higher rate of return than debt and if

the traditional AFUDC rate was used the Corporation would earn higher interest for

assets under construction. However, as discussed for the 2013/14 Test Year the

difference between approaches is only $0.020 million or 0.0186% of revenue

requirement. The Corporation cannot use traditional AFUDC under IFRS. Had AFUDC

been maintained for regulatory reporting, the Corporation would need to maintain two

Information Request

NTPC GRA 2012/13 and 2013/14


BR.NTPC-8


sets of asset databases and there would need to be a perpetual reconciling item

between IFRS financial statements and regulatory statements for each capital project.

Increased costs and administration could result if the Corporation was required to

maintain two asset databases.

Information Request

NTPC GRA 2012/13 and 2013/14


BR.NTPC-9


TOPIC:

Cost of Capital

REFERENCE:

Section 3.5

PREAMBLE:

The Board wishes to assess the implications of NTPC's capital structure/rate of return

proposals for the Corporation's long term cost of borrowing.

REQUEST:

a) Please discuss the implications of the following proposed changes to capital

structure and cost of capital on the Corporation's overall investment risk and the

implications thereof for the long term cost of borrowing and financial viability of

the Corporation:

• The proposal to adopt an ROE that is below the industry benchmark: In

this case NTPC has requested an ROE of 8.5% compared with the

industry benchmark of 8.75% based on the AUC's December 8, 2011

Decision.

• No return on equity. However, the effective cost of debt set to 1.5 times

the forecast debt cost rate for the thermal zone consistent with Electricity

Restructuring Guidelines.

• Adoption of IDC in place of AFUDC.

• Adopting a Corporate debt equity ratio that is higher than the regulatory

debt equity ratio financing rate base.

b) Please provide the funds from operations to total debt coverage ratio and the

debt interest coverage ratios for each of 2007/08 GTA forecast 2007/08 actual

and for 2010/11 actual, 2011/12 actual, 2012/13 forecast and 2013/14 forecast.

Information Request

NTPC GRA 2012/13 and 2013/14


BR.NTPC-9


RESPONSE:

(a)

The cost of capital changes proposed by the Corporation do not change the

Corporation’s overall investment risk, and were adopted primarily to simplify financial

reporting and regulation.

In this Application the Corporation is proposing a lower ROE than the latest approved in

Alberta and is maintaining the Rate Policy Guidelines interest coverage ratio on Thermal

assets. In conjunction with the four year rate transition proposed in this Application and

the commitment from the GNWT on behalf of Customers, the interest coverage ratio and

ROE allow the Corporation to finance its ongoing debt obligations and finance its

ongoing asset base while minimizing rate shock to Customers.

In a traditional sense a lower return on equity through a lower rate or through eliminating

an equity component could increase a company’s financial risk. Lower equity returns can

reduce net income and the amount of equity a company requires to finance its asset

base. Lower revenue could make it more difficult for companies to finance current and

future debt obligations. Ultimately a company could have reduced asset reliability and

service quality if funds need to be reallocated to finance ongoing debt obligations.

As discussed in the Corporation’s response to BR.NTPC-8(d), changes to the AFUDC

rate do not have a material impact on the financial viability of the Corporation.

(b)

Please see Table 1 below. The 2011/12 year-end audit is currently being finalized and

audited results are not available.

Information Request

NTPC GRA 2012/13 and 2013/14


BR.NTPC-9


Table 1:

Interest Coverage Ratio and Cash Flow from Operations (CFO) to Total Debt Ratio

2007/08 Test Year

2007/08 Actual

2010/11 Actual

2012/13 Forecast

2013/14 Forecast

Interest Coverage Ratio 1.49 1.80 1.44 1.59 1.82 CFO / Total Debt Ratio 0.15 0.16 0.09 0.11 0.14

Information Request

NTPC GRA 2012/13 and 2013/14


BR.NTPC-10


TOPIC:

Territorial Fuel and Water Stabilization Fund

REFERENCE:

Section 3.6

PREAMBLE:

The Board wishes to examine the parameters and operation of the various fuel and

water stabilization funds.

REQUEST:

a) Please provide a continuity Schedule, by fiscal year, for each of the fuel and

water stabilization funds (diesel, Inuvik, Norman Wells, Taltson, Snare-

Yellowknife fuel, Snare-Yellowknife water) from the time of the Electricity

Restructuring to year end 2013/14.

b) Provide a detailed description of the purpose and operation of each fund

including the applicable thresholds.

c) With respect to each fund, please provide illustrative examples of the information

that will be provided to the Board at the time an application is submitted for

recovery/refund of fund balances including details of the mechanics of how the

rate rider(s) will be calculated.

d) Please confirm the 1.2 GWh reflects the forecast diesel generation for peaking

and exercising at Snare-Yellowknife. Please provide the cost of this generation

for 2012/13 and 2013/14. Provide detailed support for how the 1.2 GWh forecast

was determined. Please include relevant historical data in order to demonstrate

the reasonableness of the forecast.

Information Request

NTPC GRA 2012/13 and 2013/14


BR.NTPC-10


e) Please discuss the pros and cons of treating the costs associated with diesel fuel

peaking and exercising at Snare-Yellowknife as a sub part of the water

stabilization deferral account versus including it in revenue requirement.

f) NTPC indicates the Norman Wells diesel generation varies from 1.02 GWh (as

assumed in the current GRA) positively or negatively and that costs or savings

associated with the variation in the generation mix flow through the Consolidated

Stabilization Fund. Please provide evidence based on historical diesel generation

and fuel use demonstrating why the 1.02 GWh level of diesel generation is

appropriate level for inclusion in revenue requirement.

RESPONSE:

(a)

In accordance with the Board Decision 16-2010, as of December 2010, Diesel, Inuvik,

Norman Wells, Taltson, Snare-Yellowknife fuel and Snare-Yellowknife water funds have

been consolidated into one NTPC Territory-wide Consolidated Fuel and Water Rate

Stabilization Fund (“RSF”). Please refer to Attachment BR.NTPC-10(a) for the continuity

schedule of the RSF for the period of 2010/11 to 2013/14.

(b)

The use of a Rate Stabilization Fund concept was established as part of the negotiated

settlement related to the Corporation’s 1995/98 Phase I GRA. The purpose of the funds

is to mitigate the adverse impact on rates of unanticipated changes in fuel costs and

deviation of hydro conditions from normal.

The present RSF reflects amendments discussed in Board Decision 16-2010.

Recording the costs to the fund driven by the fuel price change is performed as follows:

i. The actual cost of diesel (and where relevant purchase power cost per kWh) is

compared to the forecast cost of fuel reflected in the base rate (i.e., the fuel cost

as approved by the Board for the latest GRA test year).

Information Request

NTPC GRA 2012/13 and 2013/14


BR.NTPC-10


ii. The difference is multiplied by the number of litres required to meet the load at

the GRA approved efficiency factor (based on actual generation).

iii. The total fuel cost variance will be charged / credited to the RSF.

iv. For changes in the source of supply (Norman Wells purchased power, Inuvik

gas) the cost implications of the change in source from GRA forecast are also

addressed via the fund. For an example, please see the Corporation’s response

to TGC.NTPC-33(b).

Charges / credits to the fund arising from the fluctuation in hydro conditions are

calculated as follows:

i. Consistent with the existing hydro approaches, the actual annual hydro

generation will be compared to the forecast (normal) annual hydro capability

(e.g., 220 GWh/year for the Snare system).

a. Where the hydro generation exceeds 220 GWh/year, a kWh savings from

above-average water will be calculated.

b. Where the hydro generation is below 220 GWh/year, but diesel is still

required on an actual basis, any diesel generation kWh in excess of that

included in rates (1.2 GWh/year) will be charged to the RSF.

ii. The kWh variance will be charged / credited to the RSF based on the GRA

approved efficiency and fuel price.

(c)

NTPC is continuing to examine alternative approaches to implementing necessary

Consolidated RSF riders to help minimize the degree of rate changes that are required

at any given time. Any such proposal would be subject to review and approval by the

Board at the time of NTPC applying for the rider.

The preference would be to establish a system that helps ensure that overall rates do

not change by more than approximately 3% at a time when implementing RSF riders,

but that the Consolidated RSF balance can be maintained within the $2.5 million “cap”

accepted by the Board in Decision 16-2010. In addition, the implementation of riders

needs to be able to occur promptly and with a very simple regulatory review, consistent

with the principles underlying the Creating a Brighter Future report for regulatory

simplicity. It is possible that rider changes may need to occur more frequently than the

Information Request

NTPC GRA 2012/13 and 2013/14


BR.NTPC-10


current 6 month cycle to help reduce the required magnitude of each rider change.

Analysis is underway to determine if these objectives can be simultaneously met under

all reasonable conditions. The Board will have the opportunity to assess these proposals

at the time of NTPC’s next RSF rider filing.

(d) and (e)

The diesel generation forecast for Snare Yellowknife includes forecast diesel for

exercising the units, estimated at 100 MWh/month. No specific diesel has been included

for peaking. This is because under current loads and conditions, it is very difficult to

forecast a specific average peaking requirement. In particular note that during the winter

of 2011/12 (October 2011 to March 2012) the total usage of diesel on the Snare system

is very close to averaging 100 MWh per month. However, in very cold periods, the

generation can go well above this average level. While a kWh value could be developed

to represent an “average” peaking load, this would be a very volatile concept to build into

base rates.

The forecast cost of diesel generation for the Snare zone is $0.321 million in 2012/13

and $0.320 million in 2013/14 as shown in Schedules 3.3.1 and 3.3.2 of the Application.

Any diesel generation required above this level is proposed to be addressed via the

RSF.

Including Snare peaking and exercising in the base revenue requirement, as compared

to permanently running these amounts through the Consolidated RSF, is preferred as

this helps ensure that base rates reflect full costs of providing service, and helps ensure

that the consolidated RSF, which is shared by all zones, is only paying for cost variability

and not the basic core elements of utility costs in a single zone.

(f)

The proposed diesel generation of 1.02 GWh is based on the actual 2010/11 diesel

generation. This is a reasonable estimate for future years, as it is representative of the

most recent operating conditions. There is little cost impact of the precise value selected,

as discussed in TGC.NTPC-33(b) which notes that the cost of diesel and the cost of

purchased power at GRA prices is very close to the same.

Information Request

NTPC GRA 2012/13 and 2013/14


BR.NTPC-10



NORTHWEST TERRITORIES POWER CORPORATION

TERRITORY-WIDE FUEL AND WATER STABILIZATION FUND

CONTINUITY SCHEDULE - 2010/11 ACTUAL

Notes:

1. The calculations are based on actual diesel and gas generation for the entire period.

2. The efficiency rates used are those approved by the Public Utilities Board in the most recent GRA.

3. The interest rate used is equal to the Prime Rate in effect at the Corporation's bank at the last actual month end, less 50 basis points, applied to the month end balance in the

funds.

Line 2010 2010 2010 2010 2010 2010 2010 2010 2010 2011 2011 2011no. Explanation April May June July August September October No vember December January February March

1 Diesel generation (MWh) 3,527 3,823 3,717 6,583 5,405 3,489 3,753 5,059 5,509 6,354 5,891 5,2662 Corporate approved plant efficiency (kWh/L) 3.592 3.574 3.580 3.544 3.525 3.590 3.592 3.582 3.589 3.596 3.595 3.597

3=1/2 Litre of Fuel Required (000) 982 1,070 1,038 1,858 1,534 972 1,045 1,412 1,535 1,767 1,638 1,4644 Approved fuel price w.a. ($/L) 0.935 0.918 0.907 0.838 0.866 0.933 0.927 0.907 0.907 0.894 0.888 0.9035 Actual fuel price w.a. ($/L) 0.969 0.955 0.991 0.991 0.962 0.966 0.963 0.968 0.953 0.951 0.949 1.011

6=5-4 Fuel price variance from approved ($/L) 0.033 0.038 0.084 0.153 0.096 0.033 0.036 0.060 0.045 0.056 0.061 0.1087=3*6 Fuel cost from diesel generation ($000) 33 40 87 283 147 32 38 85 70 100 100 158

8 Gas generation (MWh) 2,461 1,925 2,065 2,019 2,149 2,093 2,214 1,862 2,199 1,104 808 1,701

9 Corporate approved plant efficiency (kWh/m3) 3.399 3.399 3.399 3.399 3.399 3.399 3.399 3.399 3.399 3.399 3.399 3.399

10=8/9 Gas Fuel Required (m3) (000) 724 566 608 594 632 616 652 548 647 325 238 50011 Approved gas price ($/m3) 0.430 0.430 0.430 0.430 0.430 0.430 0.430 0.430 0.430 0.430 0.430 0.43012 Actual gas price ($/m3) 0.392 0.392 0.392 0.392 0.411 0.411 0.411 0.411 0.411 0.411 0.411 0.411

13=12-11 Gas price variance from approved ($/m3) (0.038) (0.038) (0.038) (0.038) (0.019) (0.019) (0.019) (0.019) (0.019) (0.019) (0.019) (0.019)14=10*13 Fuel cost from gas generation ($000) (28) (22) (23) (23) (12) (12) (13) (11) (12) (6) (5) (10)

15 Fuel cost due to difference in gas generation ($000) 4 32 9 13 3 11 11 66 59 171 177 114

16 Purchased power (MWh) 659 650 671 194 414 430 731 796 918 947 857 84417 Approved purchased power price ($/kWh) 0.279 0.279 0.279 0.279 0.279 0.279 0.279 0.279 0.279 0.279 0.279 0.27918 Actual purchased power price ($/kWh) 0.261 0.261 0.261 0.250 0.250 0.250 0.285 0.285 0.285 0.313 0.313 0.313

19=18-17 Purchased power price variance ($/kWh) (0.018) (0.018) (0.018) (0.029) (0.029) (0.029) 0.006 0.006 0.006 0.034 0.034 0.03420=16*19 Fuel cost from purchased power ($000) (12) (11) (12) (6) (12) (13) 4 5 5 32 29 29

21 Diesel generation due to water level (MWh) 4 10 523 3,403 1,566 23 35 465 368 78 327 7422 Approved plant efficiency (kWh/L) 3.500 3.500 3.500 3.500 3.500 3.500 3.500 3.500 3.500 3.500 3.500 3.500

23=21/22 Litre of Fuel Required (000) 1 3 149 972 448 7 10 133 105 22 94 2124 Snare zone GRA fuel price ($/L) 0.757 0.757 0.757 0.757 0.757 0.757 0.757 0.757 0.757 0.757 0.757 0.757

25=23*24 Fuel cost due to water level ($000) 1 2 113 736 339 5 7 101 80 17 71 16

26 Additional (Less) Diesel / Gas Cost ($000) (1) 41 175 1,004 4 64 25 48 246 202 314 372 307

Consolidated Fund Continuity ($000)27 Opening Deficiency (Surplus) 10,123 10,019 9,702 9,520 10,252 10,408 10,104 9,814 9,706 9,665 2,996 3,37328 Refund/ (Collection) Rider (117) (373) (373) (291) (328) (350) (358) (375) (248) (34) (1) (4)29 Snare Cascades Transfer (85)30 Shortfall Rider Applied to Stab Fund (3,901)31 Rider Payment by GNWT (3,000)32 Additional (Less) Diesel Cost (L11) (1) 41 175 1,004 464 25 48 246 202 314 372 30733 Fuel storage cost 0 0 0 0 1 1 0 0 (15) 30 0 034 Closing Balance Before Interest 10,005 9,688 9,504 10,233 10,388 10,083 9,794 9,686 9,645 2,989 3,366 3,67735 Interest Charged (Earned) 15 14 16 19 19 21 20 20 20 6 7 8

36 Closing Deficiency (Surplus) 10,019 9,702 9,520 10,252 10,408 10,104 9,814 9,706 9,665 2,996 3,373 3,685

Actual

Information Request

NTPC GRA 2012/13 and 2013/14


BR.NTPC-10


Attachment BR.NTPC-10(a) Con’t



CONTINUITY SCHEDULE - 2011/12 ACTUAL

Notes:

1. The calculations are based on actual diesel and gas generation for the entire period.

2. The efficiency rates used are those approved by the Public Utilities Board in the most recent GRA.


funds.

Line 2011 2011 2011 2011 2011 2011 2011 2011 2011 2012 2012 2012no. Explanation April May June July August September October No vember December January February March

1 Diesel generation (MWh) 4,564 4,260 4,087 3,691 4,228 3,380 3,836 4,287 4,177 5,554 6,581 6,6592 Corporate approved plant efficiency (kWh/L) 3.596 3.589 3.598 3.561 3.528 3.580 3.586 3.581 3.583 3.591 3.604 3.604

3=1/2 Litre of Fuel Required (000) 1,269 1,187 1,136 1,037 1,198 944 1,070 1,197 1,166 1,546 1,826 1,8484 Approved fuel price w.a. ($/L) 0.905 0.908 0.902 0.901 0.902 0.932 0.933 0.929 0.942 0.914 0.882 0.8855 Actual fuel price w.a. ($/L) 1.010 1.040 1.032 1.055 1.073 1.127 1.133 1.150 1.153 1.155 1.147 1.157


8 Gas generation (MWh) 1,238 1,517 1,239 2,327 2,195 2,305 2,395 2,664 2,902 1,924 121 342

9 Corporate approved plant efficiency (kWh/m3) 3.399 3.399 3.399 3.399 3.399 3.399 3.399 3.399 3.399 3.399 3.399 3.39910=8/9 Gas Fuel Required (m3) (000) 364 446 365 685 646 678 705 784 854 566 36 101

11 Approved gas price ($/m3) 0.430 0.430 0.430 0.430 0.430 0.430 0.430 0.430 0.430 0.430 0.430 0.43012 Actual gas price ($/m3) 0.411 0.411 0.411 0.411 0.499 0.499 0.499 0.499 0.499 0.499 0.499 0.499

13=12-11 Gas price variance from approved ($/m3) (0.019) (0.019) (0.019) (0.019) 0.069 0.069 0.069 0.069 0.069 0.069 0.069 0.06914=10*13 Fuel cost from gas generation ($000) (7) (9) (7) (13) 45 47 49 54 59 39 2 7

15 Fuel cost due to difference in gas generation ($000) 118 70 86 (16) (1) (8) (5) (8) (6) 103 267 240

16 Purchased power (MWh) 706 598 709 628 616 470 792 783 1,073 855 986 89617 Approved purchased power price ($/kWh) 0.279 0.279 0.279 0.279 0.279 0.279 0.279 0.279 0.279 0.279 0.279 0.27918 Actual purchased power price ($/kWh) 0.347 0.347 0.347 0.326 0.326 0.326 0.361 0.361 0.361 0.357 0.357 0.357

19=18-17 Purchased power price variance ($/kWh) 0.068 0.068 0.068 0.047 0.047 0.047 0.082 0.082 0.082 0.078 0.078 0.07820=16*19 Fuel cost from purchased power ($000) 48 41 48 30 29 22 65 64 88 67 77 70

21 Diesel generation due to water level (MWh) 11 105 77 566 251 227 133 234 102 47 0 2022 Approved plant efficiency (kWh/L) 3.500 3.500 3.500 3.500 3.500 3.500 3.500 3.500 3.500 3.500 3.500 3.500

23=21/22 Litre of Fuel Required (000) 3 30 22 162 72 65 38 67 29 13 0 624 Snare zone GRA fuel price ($/L) 0.757 0.757 0.757 0.757 0.757 0.757 0.757 0.757 0.757 0.757 0.757 0.757


26 Additional (Less) Diesel / Gas Cost ($000) 295 282 292 283 3 32 295 351 426 410 591 830 823

Consolidated Fund Continuity ($000)27 Opening Deficiency (Surplus) 3,685 3,988 1,275 1,570 1,857 2,194 1,492 1,847 2,278 2,693 2,189 3,02528 Refund/ (Collection) Rider 0 0 () 0 0 () 0 0 0 0 0 029 Rider Payment by GNWT 0 (3,000) 0 0 0 (1,000) 0 0 0 (1,100) 0 030 Additional (Less) Diesel Cost (L11) 295 282 292 283 332 295 351 426 410 591 830 82331 Fuel storage cost 0 3 0 0 0 0 0 0 0 0 0 032 Closing Balance Before Interest 3,980 1,272 1,567 1,853 2,190 1,489 1,843 2,273 2,688 2,184 3,019 3,84833 Interest Charged (Earned) 8 3 3 4 5 3 4 5 6 5 6 83435 Closing Deficiency (Surplus) 3,988 1,275 1,570 1,857 2,194 1,492 1,847 2,278 2,693 2,189 3,025 3,856

Actual

Information Request

NTPC GRA 2012/13 and 2013/14


BR.NTPC-10





CONTINUITY SCHEDULE – 2012/13 FORECAST

Notes:

1. The calculations are based on forecast diesel and gas generation for the entire period.

2. The efficiency rates used are those proposed in 2012/14 GRA.


funds.

Line 2012 2012 2012 2012 2012 2012 2012 2012 2012 2013 2013 2013no. Explanation April May June July August September Octobe r November December January February March

1 Diesel generation (MWh) 6,336 5,913 5,674 5,124 5,869 4,693 5,325 5,951 5,799 7,710 9,136 9,2442 Corporate proposed plant efficiency (kWh/L) 3.532 3.532 3.532 3.532 3.532 3.532 3.532 3.532 3.532 3.532 3.532 3.532

3=1/2 Litre of Fuel Required (000) 1,794 1,674 1,606 1,451 1,662 1,329 1,508 1,685 1,642 2,183 2,587 2,6174 Proposed fuel price w.a. ($/L) 1.129 1.129 1.129 1.129 1.129 1.129 1.129 1.129 1.129 1.129 1.129 1.1295 Actual fuel price w.a. ($/L) 1.129 1.129 1.129 1.129 1.129 1.129 1.129 1.129 1.129 1.129 1.129 1.129


8 Gas generation (MWh) 0 0 0 0 0 0 0 0 0 0 0 09 Corporate approved plant efficiency (kWh/m3) 3.350 3.350 3.350 3.350 3.350 3.350 3.350 3.350 3.350 3.350 3.350 3.350

10=8/9 Gas Fuel Required (m3) (000) 0 0 0 0 0 0 0 0 0 0 0 011 Proposed gas price ($/m3) 0.499 0.499 0.499 0.499 0.499 0.499 0.499 0.499 0.499 0.499 0.499 0.49912 Actual gas price ($/m3) 0.499 0.499 0.499 0.499 0.499 0.499 0.499 0.499 0.499 0.499 0.499 0.499

13=12-11 Gas price variance from approved ($/m3) 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.00014=10*13 Fuel cost from gas generation ($000) 0 0 0 0 0 0 0 0 0 0 0 0


16 Purchased power (MWh) 649 549 652 578 566 432 728 720 986 786 907 82417 Proposed purchased power price ($/kWh) 0.357 0.357 0.357 0.357 0.357 0.357 0.357 0.357 0.357 0.357 0.357 0.35718 Actual purchased power price ($/kWh) 0.357 0.357 0.357 0.357 0.357 0.357 0.357 0.357 0.357 0.357 0.357 0.357


21 Fuel cost due to difference in PP generation ($000) 0 0 0 0 0 0 0 0 0 0 0 0

22 Diesel generation above 1.2 GWh due to water level (MWh) 0 0 0 0 0 0 0 0 0 0 0 023 Proposed plant efficiency (kWh/L) 3.641 3.641 3.641 3.641 3.641 3.641 3.641 3.641 3.641 3.641 3.641 3.641

24=22/23 Litre of Fuel Required (000) 0 0 0 0 0 0 0 0 0 0 0 025 Snare zone proposed GRA fuel price ($/L) 0.973 0.973 0.973 0.973 0.973 0.973 0.973 0.973 0.973 0.973 0.973 0.973



29=27/28 Litre of Fuel Required (000) 0 0 0 0 0 0 0 0 0 0 0 030 Taltson zone proposed GRA fuel price ($/L) 1.039 1.039 1.039 1.039 1.039 1.039 1.039 1.039 1.039 1.039 1.039 1.039


32 Additional (Less) Diesel / Gas Cost ($000) 0 0 0 0 0 0 0 0 0 0 0 0

Consolidated Fund Continuity ($000)33 Opening Deficiency (Surplus) 3,856 0 0 0 0 0 0 0 0 0 0 034 Refund/ (Collection) Rider35 Rider Payment by GNWT (3,856)36 Additional (Less) Diesel Cost (L11) 0 0 0 0 0 0 0 0 0 0 0 037 Fuel storage cost38 Closing Balance Before Interest 0 0 0 0 0 0 0 0 0 0 0 039 Interest Charged (Earned) 0 0 0 0 0 0 0 0 0 0 0 0

40 Closing Deficiency (Surplus) 0 0 0 0 0 0 0 0 0 0 0 0

Forecast

Information Request

NTPC GRA 2012/13 and 2013/14


BR.NTPC-10





CONTINUITY SCHEDULE – 2013/14 FORECAST

Notes:

1. The calculations are based on forecast diesel and gas generation for the entire period.

2. The efficiency rates used are those proposed in 2012/14 GRA.


funds.

Line 2013 2013 2013 2013 2013 2013 2013 2013 2013 2014 2014 2014no. Explanation April May June July August September Octobe r November December January February March

1 Diesel generation (MWh) 6,452 6,021 5,778 5,218 5,976 4,778 5,423 6,060 5,905 7,851 9,303 9,4132 Corporate proposed plant efficiency (kWh/L) 3.543 3.543 3.543 3.543 3.543 3.543 3.543 3.543 3.543 3.543 3.543 3.543

3=1/2 Litre of Fuel Required (000) 1,821 1,699 1,631 1,473 1,687 1,349 1,530 1,710 1,667 2,216 2,626 2,6574 Proposed fuel price w.a. ($/L) 1.129 1.129 1.129 1.129 1.129 1.129 1.129 1.129 1.129 1.129 1.129 1.1295 Actual fuel price w.a. ($/L) 1.129 1.129 1.129 1.129 1.129 1.129 1.129 1.129 1.129 1.129 1.129 1.129


8 Gas generation (MWh) 0 0 0 0 0 0 0 0 0 0 0 0

9 Corporate approved plant efficiency (kWh/m3) 3.356 3.356 3.356 3.356 3.356 3.356 3.356 3.356 3.356 3.356 3.356 3.356

10=8/9 Gas Fuel Required (m3) (000) 0 0 0 0 0 0 0 0 0 0 0 011 Proposed gas price ($/m3) 0.499 0.499 0.499 0.499 0.499 0.499 0.499 0.499 0.499 0.499 0.499 0.49912 Actual gas price ($/m3) 0.499 0.499 0.499 0.499 0.499 0.499 0.499 0.499 0.499 0.499 0.499 0.499

13=12-11 Gas price variance from approved ($/m3) 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.00014=10*13 Fuel cost from gas generation ($000) 0 0 0 0 0 0 0 0 0 0 0 0


16 Purchased power (MWh) 645 547 649 575 563 430 724 716 981 782 902 82017 Proposed purchased power price ($/kWh) 0.357 0.357 0.357 0.357 0.357 0.357 0.357 0.357 0.357 0.357 0.357 0.35718 Actual purchased power price ($/kWh) 0.357 0.357 0.357 0.357 0.357 0.357 0.357 0.357 0.357 0.357 0.357 0.357


21 Fuel cost due to difference in PP generation ($000) 0 0 0 0 0 0 0 0 0 0 0 0


24=22/23 Litre of Fuel Required (000) 0 0 0 0 0 0 0 0 0 0 0 025 Snare zone proposed GRA fuel price ($/L) 0.973 0.973 0.973 0.973 0.973 0.973 0.973 0.973 0.973 0.973 0.973 0.973



29=27/28 Litre of Fuel Required (000) 0 0 0 0 0 0 0 0 0 0 0 030 Taltson zone proposed GRA fuel price ($/L) 1.039 1.039 1.039 1.039 1.039 1.039 1.039 1.039 1.039 1.039 1.039 1.039


32 Additional (Less) Diesel / Gas Cost ($000) 0 0 0 0 0 0 0 0 0 0 0 0

Consolidated Fund Continuity ($000)33 Opening Deficiency (Surplus) 0 0 0 0 0 0 0 0 0 0 0 034 Refund/ (Collection) Rider35 Rider Payment by GNWT 36 Additional (Less) Diesel Cost (L11) 0 0 0 0 0 0 0 0 0 0 0 037 Fuel storage cost38 Closing Balance Before Interest 0 0 0 0 0 0 0 0 0 0 0 039 Interest Charged (Earned) 0 0 0 0 0 0 0 0 0 0 0 0

40 Closing Deficiency (Surplus) 0 0 0 0 0 0 0 0 0 0 0 0

Forecast

Information Request

NTPC GRA 2012/13 and 2013/14


BR.NTPC-11


TOPIC:

Depreciation (Amortization)

REFERENCE:

Section 3.4; Page 3-13, Page 6-18

PREAMBLE:

"Gannett Fleming’s analysis indicates NTPC is presently in a $20.2 million surplus

position with respect to negative salvage. The study also indicates that absent this

surplus, the annual charges that should be imposed for future net salvage costs would

be $1.4 million per year. In light of the surplus, NTPC is proposing not to impose the

$1.4 million per year annual salvage accrual into rates at this time, but rather to 'turn off'

or 'pause' the annual salvage provision to gradually permit the surplus to be decreased

over time."

REQUEST:

a) Please provide the calculations by account showing the derivation of the $20.2

million surplus position with respect to negative salvage. Provide all supporting

analysis and evidence used to arrive at the conclusion that a $20.2 million

surplus position exists with respect to negative salvage.

b) NTPC states Gannett Fleming concluded that on an ongoing basis, the normal

requiredprovision for future removal should total $1.5 million per year. Please

explain what is meant by normal required provision for future removal? Provide

details of how the $1.5 million annual provision was determined.

c) Please discuss how, known legal obligations as well as potential and/or

contingent liabilities for future removal and site restoration costs were dealt with

in the analysis referred to in a).

d) Please discuss how environmental clean up costs associated with future removal

and site restoration were dealt with in the analysis referred to in a).

Information Request

NTPC GRA 2012/13 and 2013/14


BR.NTPC-11


e) By reference to Table 3.8, please provide a schedule showing, by account, the

calculation of the $1.038 million increase in amortization expense due to

increased amortization rates.

f) By reference to Table 3.8, please provide a schedule showing, by account, the

calculation of the $2.098 million reduction in amortization expense due to

reduction from negative salvage correction.

RESPONSE:

(a) and (b)

Please refer to Table 1 and Table 2 below illustrating the $1.5 million annual

amortization provision for negative salvage and the $20.2 million negative salvage

variance under the “traditional approach”.

Table 2 also shows the annual true-up for negative salvage which is $0.160 million using

the same traditional approach. As a result, the net impact of the negative salvage

component under this approach is $1.4 million ($1.538 million less $0.160 million). The

$0.160 million is calculated by refunding or collecting variances for each FERC class

over the probable life remaining for that class. Although Gannett Fleming calculates the

reserve variance to be greater than $20 million, the annual true up provision or refund is

very low at only $0.160 million per year. This is because, as shown in Table 2, the

majority of FERC accounts with significant surplus balances are hydro, transmission and

distribution plant which have longer lives, while the shorter lived assets have less

surplus or have deficits in the salvage accounts. Under these circumstances if the

Corporation was applying for a traditional amortization approach it would be asking the

Board to approve a $1.538 million annual collection for negative salvage but only provide

a $0.160 million annual refund for the $20 million reserve variance.

Instead of the traditional approach, which is much less beneficial to customers, NTPC is

proposing not to impose the net $1.4 million per year annual salvage accrual into rates

at this time, but rather to 'turn off' or 'pause' the annual salvage provision to gradually

permit the surplus to be decreased over time.

Information Request

NTPC GRA 2012/13 and 2013/14


BR.NTPC-11


Table 1: Negative Salvage Calculation – Traditional Approach

ORIGINAL COSTSURVIVOR SALVAGE AT ANNUAL ANNUAL CALCULATED

DESCRIPTION CURVE PERCENT March 31, 2011 RATE AMOUNT ACCRUEDACCOUNT (1) (2) (3) (4) (5) (6) (7)

OTHER UTILITY PROPERTY121 RESIDUAL HEAT SYSTEM

EQUIPMENT 0 0.00 - 0.00 - - WIND TURBINES 0 0.00 382,968 0.00 - - TOTAL ACCOUNT 121 382,968 - -

131 RESIDUAL HEAT SYSTEM 0 0.00 2,863,613 0.00 - - TOTAL OTHER UTILITY PROPERTY 3,246,581 0.00 - -

HYDRO PLANT331 STRUCTURES AND IMPROVEMENTS 0 * -5.00 21,029,535 0.05 10,515 335,058 332 RESERVOIRS, DAMS AND WATERWAYS 0 * -5.00 39,269,484 0.05 19,635 482,808 333 WATER WHEELS, TURBINES AND GENERATORS 0 * -5.00 28,251,289 0.08 21,753 413,656 334 ACCESSORY ELECTRIC EQUIPMENT 0 * -2.00 18,661,596 0.06 12,055 140,355 335 MISCELLANEOUS POWER PLANT EQUIPMENT 0 * -2.00 3,733,316 0.13 4,952 36,270 336 ROADS, RAILROADS, AND BRIDGES 0 * -2.00 10,681,479 0.03 2,841 52,864

TOTAL HYDRO PLANT 121,626,700 0.06 71,751 1,461,011

DIESEL PLANT341 STRUCTURES AND IMPROVEMENTS 0 -25.00 40,921,982 0.83 340,676 4,671,950 342 FUEL HOLDERS, PRODUCERS AND ACCESSORIES 0 -60.00 12,839,360 2.00 256,530 2,771,416 343 PRIME MOVERS 0 -25.00 48,087,155 1.15 550,637 7,004,222 344 GENERATORS 0 -5.00 7,304,149 0.18 13,038 150,597 345 ACCESSORY ELECTRIC EQUIPMENT 0 -10.00 19,767,023 0.48 94,059 1,076,537 346 MISCELLANEOUS POWER PLANT EQUIPMENT 0 0.00 1,917,970 0.00 - -

TOTAL DIESEL PLANT 130,837,640 0.96 1,254,940 15,674,722

TRANSMISSION PLANT351 CLEARING LAND AND LAND RIGHTS 0 * 0.00 3,122,365 0.00 - - 352 STRUCTURES AND IMPROVEMENTS 0 -10.00 3,797,181 0.25 9,492 156,010 353 STATION EQUIPMENT 0 -10.00 13,222,806 0.32 42,709 517,719 354 TOWERS AND FIXTURES 0 * -25.00 15,134,884 0.38 58,269 1,330,762 355 POLES AND FIXTURES 0 * -20.00 1,597,176 0.44 7,092 84,302 356 OVERHEAD CONDUCTORS AND DEVICES 0 * -25.00 10,797,272 0.42 45,079 - 357 UNDERGROUND CONDUIT 0 0.00 12,434 0.00 - - 358 UNDERGROUND CONDUCTORS AND DEVICES 0 0.00 16,344 0.00 - - 359 ROADS AND TRAILS 0 0.00 1,009,617 0.00 - -

TOTAL TRANSMISSION PLANT 48,710,078 0.33 162,641 2,088,793

CALCULATED DEPRECIATION

Information Request

NTPC GRA 2012/13 and 2013/14


BR.NTPC-11


Table 1 Con’t: Negative Salvage Calculation – Traditional Approach

ORIGINAL COSTSURVIVOR SALVAGE AT ANNUAL ANNUAL CALCULATED

DESCRIPTION CURVE PERCENT March 31, 2011 RATE AMOUNT ACCRUEDACCOUNT (1) (2) (3) (4) (5) (6) (7)

DISTRIBUTION PLANT361 STRUCTURES AND IMPOVEMENTS 0 -10.00 830,476 0.25 2,076 21,800 362 STATION EQUIPMENT 0 0.00 1,647,906 0.00 - - 364 POLES, TOWERS, AND FIXTURES 0 -25.00 12,145,150 0.56 67,406 1,104,086 365 OVERHEAD CONDUCTORS AND DEVICES 0 -20.00 3,970,086 0.44 17,627 377,288 366 UNDERGROUND CONDUIT 0 0.00 66,922 0.00 - - 367 UNDERGROUND CONDUCTORS AND DEVICES 0 0.00 275,956 0.00 - - 368 LINE TRANSFORMERS 0 0.00 4,639,577 0.00 - - 369 SERVICES 0 -10.00 1,864,199 0.18 3,393 67,372 370 METERS 0 0.00 2,404,573 0.00 - - 371 INSTALLATIONS ON CUSTOMER PREMISES 0 0.00 10,770 0.00 - - 373 STREET LIGHTING AND SIGNAL SYSTEMS 0 -15.00 792,072 0.33 2,638 33,710

TOTAL DISTRIBUTION PLANT 28,647,687 0.33 93,140 1,604,256

GENERAL PLANT390 STRUCTURES AND IMPROVEMENTS

HAY RIVER OFFICE BUILDINGS 0 * 15.00 4,737,478 (0.15) 7,106- 107,344- OTHER SMALL STRUCTURES 0 -5.00 6,367,407 0.31 19,623 190,013 TOTAL STRUCTURES AND IMPROVEMENTS 11,104,885 0.11 12,517 82,669

391.01 OFFICE FURNITURE AND EQUIPMENT - COMPUTERS 0 0.00 7,148,485 0.00 - - 391.02 OFFICE FURNITURE AND EQUIPMENT - FURNITURE 0 0.00 689,939 0.00 - -

392 TRANSPORTATION EQUIPMENT 0 10.00 3,129,655 (1.55) 40,141- 187,425- 393 STORES EQUIPMENT 0 0.00 76,068 0.00 - - 394 TOOLS, SHOP AND GARAGE EQUIPMENT 0 0.00 349,085 0.00 - - 395 LABORATORY EQUIPMENT 0 0.00 330,756 0.00 - - 396 POWER OPERATED EQUIPMENT 0 10.00 4,514,856 (4.79) 16,705- 115,641- 397 COMMUNICATION EQUIPMENT 0 0.00 6,187,841 0.00 - - 398 MISCELLANOUS EQUIPMENT 0 0.00 649,599 0.00 - - 399 OTHER TANGIBLE PLANT 0 0.00 124,015 0.00 - -

TOTAL GENERAL PLANT 34,305,184 (0.13) 44,329- 220,397-

TOTAL DEPRECIABLE PLANT 367,373,869 0.42 1,538,143 20,608,385

CALCULATED DEPRECIATION

Information Request

NTPC GRA 2012/13 and 2013/14


BR.NTPC-11


Table 2: Negative Salvage Variance Calculation– Traditional Approach

ORIGINAL COST CALCULATED BOOK PROBABLE ANNUALAT ACCRUED ACCUMULATED REMAINING PROVISION

ACCOUNT DESCRIPTION MARCH 31, 2011 DEPRECIATION DEPRECIATION AMOUNT PERCENT LIFE FOR TRUE-UP(1) (2) (3) (4) (5) (6) (7)=(4)/(6)

OTHER UTILITY PROPERTY121 RESIDUAL HEAT SYSTEM

EQUIPMENT 0 0 0 0 0.00 0.00 WIND TURBINES 382,968 0 0 0.00 3.50 0.00TOTAL ACCOUNT 121 382,968 0 0 0 0.00 0.00

131 RESIDUAL HEAT SYSTEM 2,863,613 0 0 0 0.00 15.60 0.00TOTAL OTHER UTILITY PROPERTY 3,246,581 0 0 0 0.00 0.00

HYDRO PLANT331 STRUCTURES AND IMPROVEMENTS 21,029,535 335,058 2,104,478 -1,769,420 (528.09) 69.70 -25,386332 RESERVOIRS, DAMS AND WATERWAYS 39,269,484 482,808 2,417,289 -1,934,481 (400.67) 75.20 -25,724333 WATER WHEELS, TURBINES AND GENERATORS 28,251,289 413,656 408,684 4,972 1.20 45.30 0334 ACCESSORY ELECTRIC EQUIPMENT 18,661,596 140,355 530,855 -390,500 (278.22) 19.50 -20,026335 MISCELLANEOUS POWER PLANT EQUIPMENT 3,733,316 36,270 247,595 -211,325 (582.65) 9.10 -23,223336 ROADS, RAILROADS, AND BRIDGES 10,681,479 52,864 0 52,864 100.00 54.30 974

TOTAL HYDRO PLANT 121,626,700 1,461,011 5,708,902 -4,247,891 0.00 -93,385

DIESEL PLANT341 STRUCTURES AND IMPROVEMENTS 40,921,982 4,671,950 838,723 3,833,227 82.05 14.10 271,860342 FUEL HOLDERS, PRODUCERS AND ACCESSORIES 12,839,360 2,771,416 502,093 2,269,323 81.88 16.40 138,373343 PRIME MOVERS 48,087,155 7,004,222 11,321,576 -4,317,354 (61.64) 11.50 -375,422344 GENERATORS 7,304,149 150,597 -660 151,257 100.44 15.70 9,634345 ACCESSORY ELECTRIC EQUIPMENT 19,767,023 1,076,537 -15,777 1,092,314 101.47 7.70 141,859346 MISCELLANEOUS POWER PLANT EQUIPMENT 1,917,970 0 -8,353 8,353 0.00 8.20 1,019

TOTAL DIESEL PLANT 130,837,640 15,674,722 12,637,603 3,037,119 19.38 187,323

TRANSMISSION PLANT351 CLEARING LAND AND LAND RIGHTS 3,122,365 0 -5,986 5,986 0.00 41.20 145352 STRUCTURES AND IMPROVEMENTS 3,797,181 156,010 208,717 -52,707 (33.78) 23.60 -2,233353 STATION EQUIPMENT 13,222,806 517,719 -16,654 534,373 103.22 19.30 27,688354 TOWERS AND FIXTURES 15,134,884 1,330,762 8,847,988 -7,517,226 (564.88) 44.60 -168,548355 POLES AND FIXTURES 1,597,176 84,302 447,114 -362,812 (430.37) 33.60 -10,798356 OVERHEAD CONDUCTORS AND DEVICES 10,797,272 0 5,959,795 -5,959,795 #DIV/0! 43.90 -135,758357 UNDERGROUND CONDUIT 12,434 0 -475 475 0.00 12.60 38358 UNDERGROUND CONDUCTORS AND DEVICES 16,344 0 552 -552 0.00 12.60 -44359 ROADS AND TRAILS 1,009,617 0 0 0.00 27.20 0

TOTAL TRANSMISSION PLANT 48,710,078 2,088,793 15,441,053 -13,352,260 (639.23) -289,511

ACCUMULATED RESERVEVARIANCE

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NTPC GRA 2012/13 and 2013/14


BR.NTPC-11


Table 2 Con’t: Negative Salvage Variance Calculation – Traditional Approach

ORIGINAL COST CALCULATED BOOK PROBABLE ANNUALAT ACCRUED ACCUMULATED REMAINING PROVISION

ACCOUNT DESCRIPTION MARCH 31, 2011 DEPRECIATION DEPRECIATION AMOUNT PERCENT LIFE FOR TRUE-UP(1) (2) (3) (4) (5) (6) (7)=(4)/(6)

DISTRIBUTION PLANT361 STRUCTURES AND IMPOVEMENTS 830,476 21,800 9,085 12,715 58.33 29.50 431362 STATION EQUIPMENT 1,647,906 0 0 0 0.00 6.40 0364 POLES, TOWERS, AND FIXTURES 12,145,150 1,104,086 4,877,264 -3,773,178 (341.75) 39.10 -96,501365 OVERHEAD CONDUCTORS AND DEVICES 3,970,086 377,288 1,879,866 -1,502,578 (398.26) 40.90 -36,738366 UNDERGROUND CONDUIT 66,922 0 0 0 0.00 17.10 0367 UNDERGROUND CONDUCTORS AND DEVICES 275,956 0 0 0 0.00 6.90 0368 LINE TRANSFORMERS 4,639,577 0 -103,200 103,200 0.00 26.40 3,909369 SERVICES 1,864,199 67,372 442,980 -375,608 (557.51) 43.70 -8,595370 METERS 2,404,573 0 0 0 0.00 4.50 0371 INSTALLATIONS ON CUSTOMER PREMISES 10,770 0 0 0 0.00 7.10 0373 STREET LIGHTING AND SIGNAL SYSTEMS 792,072 33,710 60,313 -26,603 (78.92) 29.30 -908

TOTAL DISTRIBUTION PLANT 28,647,687 1,604,256 7,166,307 -5,562,051 0.00 -138,402

GENERAL PLANT390 STRUCTURES AND IMPROVEMENTS

HAY RIVER OFFICE BUILDINGS 4,737,478 -107,344 594,835 -702,179 654.14 85.40 -8,222 OTHER SMALL STRUCTURES 6,367,407 190,013 190,013 100.00 8.10 23,458TOTAL STRUCTURES AND IMPROVEMENTS 11,104,885 82,669 594,835 -512,166 (619.54) 15,236

391 OFFICE FURNITURE AND EQUIPMENT 7,838,423 0 -200,877 200,877 0.00 5.00 40,175392 TRANSPORTATION EQUIPMENT 3,129,655 -187,425 -506,751 319,326 0.00 2.60 122,818393 STORES EQUIPMENT 76,068 0 0 0.00 10.50 0394 TOOLS, SHOP AND GARAGE EQUIPMENT 349,085 0 0 0.00 8.30 0395 LABORATORY EQUIPMENT 330,756 0 0 0.00 4.50 0396 POWER OPERATED EQUIPMENT 4,514,856 -115,641 -115,641 0.00 21.40 -5,404397 COMMUNICATION EQUIPMENT 6,187,841 0 -9,700 9,700 0.00 15.20 638398 MISCELLANOUS EQUIPMENT 649,599 0 0 0.00 10.00 0399 OTHER TANGIBLE PLANT 124,015 0 0 0.00 16.40 0

TOTAL GENERAL PLANT 34,305,184 -220,397 -122,493 -97,904 44.42 173,464

TOTAL DEPRECIABLE PLANT 367,373,869 20,608,385 40,831,371 -20,222,986 (98.13) -160,511

ACCUMULATED RESERVEVARIANCE

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BR.NTPC-11


(c)

Consistent with past practice and standard utility practice the salvage rates were

estimated based on full removal of assets and not focusing solely on specific legal

obligations or contingent liabilities.

(d)

Estimated clean-up costs are included in the estimated salvage in part (a).

(e)

Please refer to Table 3 below comparing the 2013/14 amortization expense at existing

rates and proposed rates.

Table 3: Amortization Expense Increase Resulting from Propos ed Rates ($000s)

Proposed Amortization

RatesCurrent Rates

Proposed Rates Change

FERC A B C D=AxB E=AxC F=E-D118 High water temp equip - - 121 Wind 383 20.00 20.00 77 77 0 131 Heat Recovery Systems 5,120 2.50 4.00 128 205 77 155 Microturbines 298 4.00 4.00 12 12 0

HYDRO ASSETS330 Land and Land Rights 4,109 - - 331 Structures & Improvements 22,275 2.16 1.00 480 223 (258)332 Resv., Dams & Waterways 53,629 1.33 1.00 713 536 (177)333 Turbines and Generators 41,810 1.58 1.54 659 644 (15)334 Accessory Electric Equip. 26,129 2.86 3.23 747 844 97 335 Misc. Power Plant Equip. 5,700 4.99 6.63 284 378 94 336 Roads & Bridges 10,841 1.16 1.33 126 144 18

DIESEL ASSETS340 Land and Land Rights 1,072 - - 341 Structures & Improvements 41,416 2.40 3.33 994 1,379 385 342 Fuel Holders, Prod., & Access. 16,714 2.69 3.33 449 557 107 343 Prime Movers 52,929 3.81 4.58 2,015 2,424 410 344 Generators 7,695 3.33 3.57 256 275 18 345 Accessory Electric Equip. 22,787 3.57 4.76 813 1,084 271 346 Misc. Power Plant Equip. 1,918 5.00 5.09 96 98 2

Amortization Expense2013/14 Mid Year

Gross Plant

Current Amortization

Rates

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BR.NTPC-11


Table 3 Con’t: Amortization Expense Increase Resulting from Propos ed Rates ($000s)

TRANSMISSION ASSETS350 Land and Land Rights 5 - - 351 Clearing Land & Rights of Way 3,122 1.09 1.54 34 48 14 352 Structures & Improvements 3,797 2.49 2.50 95 95 0 353 Station Equipment 14,120 2.84 3.23 401 456 55 354 Towers & Fixtures 15,367 1.23 1.54 189 237 48 355 Poles & Fixtures 1,738 1.88 2.22 33 39 6 356 OH Conductors & Devices 10,805 1.85 1.67 199 180 (19)357 Underground Conduit 12 4.00 4.00 0 0 (0)358 Underground Conduct. & Dev. 16 4.00 4.00 1 1 0 359 Roads & Trails 1,010 4.00 2.50 40 25 (15)

DISTRIBUTION ASSETS - 360 Land and Land Rights 661 - - 361 Structures & Improvements 830 2.50 2.50 21 21 0 362 Station Equipment 1,648 2.86 3.33 47 55 8 363 Storage Battery Equip. 94 3.33 3.33 3 3 - 364 Poles & Fixtures 13,034 2.80 2.22 364 289 (75)365 OH Conductors & Devices 4,901 2.80 2.22 137 109 (28)366 Underground Conduit 67 4.00 4.00 3 3 0 367 Undergrd Conduct. & Devices 276 4.00 4.00 11 11 (0)368 Line Transformers 5,132 2.86 2.50 147 128 (18)369 Services 2,322 2.74 1.82 64 42 (21)370 Meters 2,790 3.33 4.73 93 132 39 371 Install. on Cust. Premises 11 3.33 5.00 0 1 0 372 Leased Prop. on Cust. Prem. - - - 0 - 373 Street Lighting 882 2.84 2.22 25 20 (5)

GENERAL PLANT ASSETS389 Land and Land Rights 262 - -

390.1 Head Office Building 9,573 1.67 1.00 160 96 (64)390.2 Structures & Improvements 11,499 6.56 6.16 754 709 (45)391.1 Computers 5,654 9.96 10.93 563 618 55 391.2 Office Furniture & Equip. 1,640 9.96 3.97 163 65 (98)391.3 Software 2,584 9.96 12.43 257 321 64

392 Transportation Equip. 4,300 8.17 12.83 351 551 200 393 Stores Equip. 76 5.56 3.84 4 3 (1)394 Tools, Shop, & Garage Equip. 566 7.55 5.50 43 31 (12)395 Laboratory Equip. 654 4.17 2.95 27 19 (8)396 Power Operated Equip. 4,558 5.00 3.70 228 169 (59)397 Communication Equip. 6,773 5.00 5.00 339 339 (0)398 Misc. Equip. 632 6.67 5.15 42 33 (10)399 Other Tangible Property 124 5.00 5.00 6 6 0

TOTAL 12,695 13,733 1,038

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BR.NTPC-11


(f) Please refer to Table 4 below comparing the 2013/14 negative salvage expense at existing rates and proposed rates.

Table 4: Negative Salvage Expense Decrease Resulting from Pr oposed Rates ($000s)

Current Rates

Proposed

Rates Change FERC A B C D=AxB E=AxC F=E-D

118 High water temp equip - - - - 121 Wind 383 - - - - - 131 Heat Recovery Systems 5,120 - - - - - 155 Microturbines 298 - - - - -

HYDRO ASSETS330 Land and Land Rights 4,109 - - - - 331 Structures & Improvements 22,275 0.11 - 25 - (25)332 Resv., Dams & Waterways 53,629 0.07 - 38 - (38)333 Turbines and Generators 41,810 0.08 - 35 - (35)334 Accessory Electric Equip. 26,129 0.15 - 39 - (39)335 Misc. Power Plant Equip. 5,700 0.26 - 15 - (15)336 Roads & Bridges 10,841 - - - - -

DIESEL ASSETS340 Land and Land Rights 1,072 - - - - 341 Structures & Improvements 41,416 0.60 - 248 - (248)342 Fuel Holders, Prod., & Access. 16,714 2.11 - 353 - (353)343 Prime Movers 52,929 1.07 - 568 - (568)344 Generators 7,695 - - - - - 345 Accessory Electric Equip. 22,787 - - - - - 346 Misc. Power Plant Equip. 1,918 - - - - -

TRANSMISSION ASSETS350 Land and Land Rights 5 - - - - 351 Clearing Land & Rights of Way 3,122 - - - - - 352 Structures & Improvements 3,797 0.13 - 5 - (5)353 Station Equipment 14,120 - - - - - 354 Towers & Fixtures 15,367 1.23 - 189 - (189)355 Poles & Fixtures 1,738 1.88 - 33 - (33)356 OH Conductors & Devices 10,805 1.85 - 199 - (199)357 Underground Conduit 12 - - - - - 358 Underground Conduct. & Dev. 16 - - - - - 359 Roads & Trails 1,010 - - - - -

2013/14 Mid Year

Gross Plant

Current Negative Salvage

Rate

Negative Salvage ExpenseProposed Negative Salvage

Rate

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BR.NTPC-11

June 8, 2012 Page 10 of 10

Table 4 Con’t: Negative Salvage Expense Decrease Resulting from Pr oposed Rates

DISTRIBUTION ASSETS - 360 Land and Land Rights 661 - - - - 361 Structures & Improvements 830 0.13 - 1 - (1)362 Station Equipment 1,648 - - - - - 363 Storage Battery Equip. 94 - - - - - 364 Poles & Fixtures 13,034 1.86 - 243 - (243)365 OH Conductors & Devices 4,901 1.86 - 91 - (91)366 Underground Conduit 67 - - - - - 367 Undergrd Conduct. & Devices 276 - - - - - 368 Line Transformers 5,132 - - - - - 369 Services 2,322 0.69 - 16 - (16)370 Meters 2,790 - - - - - 371 Install. on Cust. Premises 11 - - - - - 372 Leased Prop. on Cust. Prem. - - - - - - 373 Street Lighting 882 0.32 - 3 - (3)

GENERAL PLANT ASSETS389 Land and Land Rights 262 - - - -

390.1 Head Office Building 9,573 0.09 - 8 - (8)390.2 Structures & Improvements 11,499 0.35 - 40 - (40)391.1 Computers 5,654 0.20- - (11) - 11391.2 Office Furniture & Equip. 1,640 0.20- - (3) - 3391.3 Software 2,584 0.20- - (5) - 5

392 Transportation Equip. 4,300 0.74- - (32) - 32393 Stores Equip. 76 - - - - 394 Tools, Shop, & Garage Equip. 566 - - - - 395 Laboratory Equip. 654 - - - - 396 Power Operated Equip. 4,558 - - - - 397 Communication Equip. 6,773 - - - - 398 Misc. Equip. 632 - - - - 399 Other Tangible Property 124 - - - -

TOTAL 2,098 - (2,098)

Information Request

NTPC GRA 2012/13 and 2013/14


BR.NTPC-12


TOPIC:

Depreciation

REFERENCE:

Appendix A, Account 341

PREAMBLE:

The Gannett Fleming Study states, the previous study recommended a 40-R2 Iowa

curve for account 341. The review of average service life estimates for the applicable

peer companies indicated a range of lives from 30 to 50 years. It is the view of Gannett

Fleming that the mortality experience as witnessed in the retirement rate study for this

account provides the basis for the development of the average service life estimate.

REQUEST:

a) Please provide the average service lives of plants that correspond to account

341 within the peer group of companies considered by Gannett Fleming and

provide possible reasons why some are below the average of the 30-50 year

range and others above the average.

b) By reference to the survivor curve shown at page A-75, please explain in greater

detail why the proposed 30S2.5 curve is more appropriate for this account than

the existing 40R2 curve. Indicate what fundamental changes contributed to the

significant decrease in average service life.

c) With respect to account 341 Gannett Fleming states, after age 29, the plant

exposed to retirement falls to below 1% of the account’s total plant exposed to

retirement, resulting in the retirement ratios and percentages surviving after age

29 being provided a significantly lesser amount of weight. Please provide an

example to illustrate why it is appropriate to provide less weight to percentages

surviving after age 29. Indicate whether the 1% surviving calculation reflects

constant dollars or nominal dollars. If it were based on constant dollars would the

1% be higher?

Information Request

NTPC GRA 2012/13 and 2013/14


BR.NTPC-12


RESPONSE:

(a)

Please refer to the Attachment BR.NTPC-12(a), being a summary of the average service

life estimates for the selected peer group of companies for all accounts. It should be

noted that the entire group of peer companies fall within the 30 to 50 year range for

account 341.

Gannett Fleming notes that average service lives in this account vary based on the size

and construction of the structures (for example brick buildings versus metal or wood

buildings), capitalization policies of the utilities regarding improvements or capital

maintenance (for example, re-roofing, or window replacement), and physical location of

the buildings.

(b)

Please refer to Attachment BR.NTPC-12(b) for a graphic comparison of the currently

recommended Iowa 30-S2.5 and the existing Iowa 40-R2. As indicated in the attachment

use of the Iowa 40-R2 would significantly over-state the interim retirement activity from

age 3 through 20. Furthermore the Iowa 40-R2 is a poor fit at all ages after age 20. In

contrast the Iowa 30-S2.5 provides a good representation of the retirement activity

through most areas of the observed life table. It is apparent from a review of the two

Iowa curves as plotted in Attachment BR-NTPC-12(b) that the recommended Iowa 30-

S2.5 provides a far superior fit to the observed life table as compared to the currently

used Iowa 40-R2.

The average service life estimates have not been modified since a review in 2001 based

on year end 2000 data. As such, this current review incorporates 11 years of additional

plant accounting data, over which time a significant amount of retirement activity has

occurred. The additional 11 years of mortality experience has indicated average service

life changes in a number of accounts, including Account 341. As indicated at pageII-24

and II-25 of the Gannett Fleming report the recommended Iowa 30-2.5 provides for a

good fit to the observed life table, and is within the range of the life estimates as

currently used by the peer group of companies. In the view of Gannett Fleming

Information Request

NTPC GRA 2012/13 and 2013/14


BR.NTPC-12


continued use of the Iowa 40-R2 is no longer appropriate and would result in a

significant level of un-depreciated investment at the time of future retirements.

(c)

The observed life table as plotted on page IV-22 of the Gannett Fleming report is

developed by plotting the Percentages Surviving as indicated at page IV-23 and IV-24 of

the Gannett Fleming report. In order to provide the requested example, it is important to

understand the arithmetic used in the development of the Percentages Surviving. The

percentage Surviving is determined by multiplying the percentage of investment

surviving at the beginning of the age interval by the survivor ratio at the age interval. For

example, the detailed calculations are provided for account 341 at page IV-23 of the

Gannett Fleming report, which indicates (for example) that at age 13.5, 99.54% of the

investment is surviving at the beginning of the age interval. Also indicated in the survivor

ratio column is the indication that 99.93% of the plant surviving at the beginning of the

age interval survives to the end of the age interval, resulting in 99.47% (being 99.54% X

99.93%) of the investment surviving at the beginning of age interval 14.5. The surviving

ratio of 0.9993% is determined by subtracting the retirement ratio from 1 (1- 0.0007 =

0.9993 at age 13.5). The retirement ratio is determined by dividing the retirement during

the age interval by the plant exposed to retirement at the beginning of the age interval

(for example $6,338 of retirement divided by $9,333,837 of plant exposed to retirement

at age 13.5 equals a retirement ratio of 0.0007 at age 13.5).

Based on the above description of the calculations used in the development of the

observed life table, the dollars of retirement as compared to the plant exposed to

retirement at each age interval are large drivers of the percentage surviving. As such, an

equal amount of retirement dollars at differing age intervals can have a significantly

different impact on the observed life table, due to the differing levels of plant exposed to

retirement at the beginning of the age interval. For example, at page IV-23 of the

Gannett Fleming report the retirements at age 3.5 of $44,174 result in a decline of the

percentage surviving by only 0.11% (from 99.99 to 99.8). However, a similar level of

retirement dollars at age 20.5 of $43,934 result in a decline in percentage surviving of

1.49% (from 83.29 to 81.80). The difference is caused by the far smaller level of plant

exposed to retirement at age 20.5 ($2,456,679) as compared to the $41,528,478 at age

3.5. At each age interval, this phenomenon is exaggerated, and in particular the

retirement ratios near the end of the accounts age intervals can often be statistically

Information Request

NTPC GRA 2012/13 and 2013/14


BR.NTPC-12


irrelevant. This issue has been discussed in a number of depreciation textbooks and

literature, where is it generally recommended that depreciation analysts should provide

less weighting on the retirement ratios results from insignificant levels of plant exposed

to retirement. It has become a generally accepted standard among depreciation analysts

that this level of statically valid plant exposed to retirement be approximately 1% of the

total plant exposed to retirement at age 0.

Information Request

NTPC GRA 2012/13 and 2013/14


BR.NTPC-12



Northwest Territories Power Corporation

Summary of the Average Service Life Estimates of Peer Electric Utilities

Approved Curve

Statistical Best Fit

Northwest Territories Yellowknife

Yukon Electrical Corp

Qulliq Energy Corporation

ATCO Electric

Manitoba Hydro AltaLink LP

Average ASL

ASL Range

GF Recommends

DIESEL PLANT341 STRUCTURES AND IMPROVEMENTS 40-R2 28-L5 50-S1.5 40-R2.5 35-R2.5 30-R3 39 30-50 30-S2.5343 PRIME MOVERS 25-S2.5 20-R3 25-R1.5 27-R2.5 25-R1.5 26 25-27 20-R3345 ACCESSORY ELECTRIC EQUIPMENT 28-S2.5 21-L4 30-R1.5 35-R3 25-R2 20-R3 28 20-35 21-L4

391.01 OFFICE FURNITURE AND EQUIPMENT - COMPUTERS 10-S1 5-SQ 5-SQ & 10-SQ 5-SQ 5-SQ 5-S0.5 5-SQ TO 10-SQ 5-SQ 6 5-10 5-SQ391.02 OFFICE FURNITURE AND EQUIPMENT - FURNITURE 10-S1 15-SQ 15-SQ 15-SQ 5-SQ 15-R3 20-SQ 15-SQ 14 5-20 15-SQ

392 TRANSPORTATION EQUIPMENT 12-S2 20-L1 9-L2 & 20-R3 10-R0.5 12-L1.5 10 - 25 YEARS VARIES* 9-L0.5 14 9-25 7-S1393 STORES EQUIPMENT 18-R2.5 25-R3 9-L0.5 17 9-25 25-R3394 TOOLS, SHOP AND GARAGE EQUIPMENT 13-S1 10-SQ 15-SQ 15-SQ 10-R2 15-SQ 9-L0.5 12 9-15 15-SQ395 LABORATORY EQUIPMENT 24-S3 20-SQ 9-L0.5 15 9-20 25-SQ396 POWER OPERATED EQUIPMENT 20-R3 30-L2.5 20-L1 25-L2 23 20-25 27-S1.5397 COMMUNICATION EQUIPMENT 20-R3 20-L3 15-R4 10-SQ 25-R3 25-R2 VARIES* 19 10-25 20-R3398 MISCELLANOUS EQUIPMENT 15-S3 15-SQ 15 15 15-SQ399 OTHER TANGIBLE PLANT 20-S3 20-SQ

Northland Utilities Inc.

NORTHWEST TERRITORIES POWER CORPORATIONACCOUNT 341 STRUCTURES AND IMPROVEMENTS

ORIGINAL AND SMOOTH SURVIVOR CURVES

NORTHWEST TERRITORIES POWER CORPORATION ACCOUNT 341 STRUCTURES AND IMPROVEMENTS

ORIGINAL AND SMOOTH SURVIVOR CURVES

Information Request NTPC GRA 2012/13 and 2013/14 NWT Public Utilities Board Attachment BR.NTPC-12(b)


Information Request

NTPC GRA 2012/13 and 2013/14


BR.NTPC-13


TOPIC:

Depreciation

REFERENCE:


PREAMBLE:

Gannett Fleming states, the Iowa curve matching procedures employed by Gannett

Fleming resulted in an Iowa 20-R3 being considered the best fit to the historic retirement

trends. The Iowa 20-R3 represents a shorter life estimate than the currently used Iowa

25-S2.5, and is shorter than the peer range of 25 to 27 year estimates. However, the site

reviews and operational staff reviews did not indicate any reason to believe that the plant

currently in service should have any significant longer life indications than has been

experienced in the past.

REQUEST:

a) Please identify the fundamental changes that may have contributed to the

decrease in average service life for account 343, from 25 years to 20 years.

b) Please provide reasons why the historical indications of average service life for

account 343 are significantly different from the average service lives of peers, for

account 343.

c) Please elaborate and provide details of the site reviews and operational staff

reviews that were conducted as a result of which Gannett Fleming came to the

conclusion that the plant currently in service would not have any significant

longer life indications than has been experienced in the past.

Information Request

NTPC GRA 2012/13 and 2013/14


BR.NTPC-13


RESPONSE:

(a)


on year-end 2000 data. As such, this current review incorporates 11 years of additional



life changes in a number of accounts, including Account 343. Over this 10 year period,

account 343 has witnessed over $13 million of retirement activity, an amount that

represents over 27% of the surviving investment. This retirement activity is summarized

in Attachment BR-NTPC-13(a), which also provides for a weighted average age of

retirement of 15.6 years for these retirement transactions. As such, the last decade has

witnessed a very large amount of retirement activity that has retired investment at an

age of 15.6 years (on average), which represents a significantly shorter life indication

than that seen in the 2001 depreciation study.

(b)

Please refer to Attachment BR.NTPC-12(a). Gannett Fleming notes that average service

lives in this account vary based on a number of factors in addition to the physical life

expectation. The number of operating hours per year varies widely among the units used

in the circumstances of isolated generation in remote communities as compared to units

that are installed to handle peak loads. Additionally, units installed in remote

communities that are not connected to any type of transmission grid are often subjected

to differing life characteristics due to increased on-going maintenance activity in order to

ensure reliability. It is also noted that there exists a number of differing manufacturers of

these units that exhibit differing performance characteristics. Last, manufacture support

for units can cause differing levels of technological obsolescence among the various

types of units and cause differences in life estimates among peer utilities.

(c)

Gannett Fleming conducted interviews with operating representatives and management

of NTPC. During these discussions the results of the preliminary average service life

analysis were reviewed and vetted with the NTPC staff, and discussions were held to

Information Request

NTPC GRA 2012/13 and 2013/14


BR.NTPC-13


understand the types of retirements that have been completed over the past number of

years. Through these interviews it was determined historical retirements resulted from

causes that were reasonable and could occur in future years. Additionally, Gannett

Fleming physically toured a number of facilities in the completion of this and previous

engagements with NTPC. During the conduct of this assignment Gannett Fleming

reviewed the physical facilities at the Jackfish and Behchoko diesel plants, and Bluefish

Hydro facility to gain an understanding of the type of units and operating conditions that

the units are subjected to.

Information Request

NTPC GRA 2012/13 and 2013/14


BR.NTPC-13


Attachment BR.NTPC-13(a) Northwest Territories Power Corporation

Summary of Retirement Activity 2001 - 2011

ACCOUNTINSTALL

YEARRETIRMENT

AMOUNTRETIREMENT

YEARAGE AT

RETIRMENT WEIGHTING 343 1962 -285,839.00 1997 35 (10,004,365.00) 343 1976 -2,000.00 2011 35 (70,000.00) 343 1968 -8,702.00 2001 33 (287,166.00) 343 1978 -47,904.36 2011 33 (1,580,843.88) 343 1975 -575,475.80 2005 30 (17,264,274.00) 343 1974 -163,981.20 2003 29 (4,755,454.80) 343 1976 -31,924.12 2004 28 (893,875.36) 343 1974 -20,598.00 2001 27 (556,146.00) 343 1978 -165,081.17 2005 27 (4,457,191.59) 343 1975 -101,805.00 2001 26 (2,646,930.00) 343 1976 -150,420.00 2001 25 (3,760,500.00) 343 1976 -226,167.91 2001 25 (5,654,197.75) 343 1973 -53,531.00 1997 24 (1,284,744.00) 343 1975 -118,899.14 1999 24 (2,853,579.36) 343 1976 -392,343.00 2000 24 (9,416,232.00) 343 1977 -54,420.00 2001 24 (1,306,080.00) 343 1974 -32,672.00 1997 23 (751,456.00) 343 1975 -8,000.00 1998 23 (184,000.00) 343 1977 -472,646.00 2000 23 (10,870,858.00) 343 1979 -6,159.00 2001 22 (135,498.00) 343 1976 -10,807.00 1997 21 (226,947.00) 343 1976 -55,580.00 1997 21 (1,167,180.00) 343 1976 -50,560.74 1997 21 (1,061,775.54) 343 1980 -78,867.00 2001 21 (1,656,207.00) 343 1981 -385,525.00 2001 20 (7,710,500.00) 343 1986 -75,020.13 2005 19 (1,425,382.47) 343 1983 -908,492.00 2001 18 (16,352,856.00) 343 1992 -150,000.00 2010 18 (2,700,000.00) 343 1984 -1,001,670.00 2001 17 (17,028,390.00) 343 1984 -431,097.00 2001 17 (7,328,649.00) 343 1981 -112,089.00 1997 16 (1,793,424.00) 343 1981 -39,687.00 1997 16 (634,992.00) 343 1982 -75,503.00 1998 16 (1,208,048.00) 343 1985 -54,481.00 2001 16 (871,696.00) 343 1989 -48,316.42 2004 15 (724,746.30) 343 1989 -99,763.42 2004 15 (1,496,451.30) 343 1991 -185,276.15 2005 14 (2,593,866.10) 343 1992 -163,773.18 2006 14 (2,292,824.52) 343 1996 -34,715.00 2010 14 (486,010.00)

Information Request

NTPC GRA 2012/13 and 2013/14


BR.NTPC-13


Attachment BR.NTPC-13(a) Con’t Northwest Territories Power Corporation

Summary of Retirement Activity 2001 - 2011

ACCOUNTINSTALL

YEARRETIRMENT

AMOUNTRETIREMENT

YEARAGE AT

RETIRMENT WEIGHTING 343 1987 -83,686.00 2000 13 (1,087,918.00) 343 1987 -631,316.72 2000 13 (8,207,117.36) 343 1987 -205,868.66 2000 13 (2,676,292.58) 343 1995 -130,112.89 2008 13 (1,691,467.57) 343 1994 -499,303.11 2005 11 (5,492,334.21) 343 1994 -288,421.84 2005 11 (3,172,640.24) 343 1994 -189,560.58 2005 11 (2,085,166.38) 343 1994 -165,902.92 2005 11 (1,824,932.12) 343 1994 -71,394.27 2005 11 (785,336.97) 343 1994 -19,396.47 2005 11 (213,361.17) 343 1994 -10,200.00 2005 11 (112,200.00) 343 1992 -1,936,232.00 2001 9 (17,426,088.00) 343 2001 -25,703.00 2010 9 (231,327.00) 343 1993 -102,079.00 2001 8 (816,632.00) 343 1995 -118,298.76 2003 8 (946,390.08) 343 1998 -89,684.20 2006 8 (717,473.60) 343 1993 -232,274.22 2000 7 (1,625,919.54) 343 1996 -404,282.15 2003 7 (2,829,975.05) 343 1999 -387,701.78 2006 7 (2,713,912.46) 343 2004 -35,000.00 2011 7 (245,000.00) 343 1992 -57,067.00 1998 6 (342,402.00) 343 2004 -240,000.00 2010 6 (1,440,000.00) 343 1996 -38,386.00 2001 5 (191,930.00) 343 1996 -2,159.00 2001 5 (10,795.00) 343 2003 -27,898.68 2008 5 (139,493.40) 343 2006 -15,967.49 2011 5 (79,837.45) 343 1996 -8,955.00 2000 4 (35,820.00) 343 1997 -9,320.00 2001 4 (37,280.00) 343 1997 -8,213.00 2001 4 (32,852.00) 343 1997 -35,000.00 2001 4 (140,000.00) 343 1997 -15,000.00 2001 4 (60,000.00) 343 1997 -15,000.00 2001 4 (60,000.00) 343 1998 -18,932.57 2002 4 (75,730.28) 343 2006 -35,000.00 2010 4 (140,000.00) 343 1995 -2,490.00 1997 2 (4,980.00) 343 1999 -155,479.00 2001 2 (310,958.00)

-13,191,078.05 (205,496,899.43)

Information Request

NTPC GRA 2012/13 and 2013/14


BR.NTPC-14


TOPIC:

Depreciation

REFERENCE:


PREAMBLE:

Gannett Fleming states the historical data indicates an Iowa Curve of 21-L4 for account

345. Gannett Fleming and NWTPC personnel agree that this account will continue to

retire assets in a similar fashion in the future. Consequently, the recommended Iowa 21-

L4 curve is representative of the past mortality trends, is within the range experienced by

the relevant peer companies and is consistent with management and operational

expectations.

REQUEST:

a) By reference to the survivor curve at page A-85, please explain why the

proposed 21L4 curve is appropriate for this account. Indicate what fundamental

changes contributed to the significant decrease in average service life from 28

years to 21 years.

b) Please provide the average service lives of plants that correspond to account

345 within the peer group of companies considered by Gannett Fleming and

rationalize the proposed average service life for account 345 in light of same for

the peer group.

RESPONSE:

(a)

The Iowa 21-L4 as provided at page A-85 (or page IV-33 of the Gannett Fleming study)

was selected on the basis of it being the statistical “best fit” to the observed life table,

and was confirmed during operational and management discussions of being reasonable

Information Request

NTPC GRA 2012/13 and 2013/14


BR.NTPC-14


to represent future retirement trends. A statistical best fit is determined by comparing the

difference of the smoothed Iowa curve at each of the age intervals to the plotted

observed life table. The difference from each plotted point to the smoothed curves are

squared, and are compared to all possible Iowa curve shapes to determine the best

“least squared difference” fit of all possible Iowa Curve shapes and average service life

combinations.


on year end 2000 data. As such, this current review incorporates 11 years of additional



life changes in a number of accounts, including Account 345. Over this 10 year period,

account 345 has witnessed over $2 million of retirement activity, an amount that

represents over 10% of the surviving investment. This retirement activity is summarized

in Attachment BR.NTPC-14(a), which also provides for a weighted average age of

retirement of 16.2 years for these retirement transactions. As such, the last decade has

witnessed a very large amount of retirement activity that has retired investment at an

age of 16.2 years (on average), which represents a significantly shorter life indication

than that seen in the 2001 depreciation study.

(b)

Please refer to Attachment BR.NTPC-12(a) for the detail summary of the peer analysis.

The recommended Iowa 21-L4 is within the band of the peer analysis. While it is noted

that the recommended 21 year life is nearer the short end of the peer range, given that

the recommendations for most of the Diesel Generation facilities are at the lower end of

the peer ranges, it would be expected that this account would follow the same trend.

Information Request

NTPC GRA 2012/13 and 2013/14


BR.NTPC-14


Attachment BR.NTPC-14(a) Northwest Territories Power Corporation

Summary of Retirement Activity 2001-2011

ACCOUNTINSTALL

YEARRETIRMENT

AMOUNTRETIREMENT

YEARAGE AT

RETIRMENT WEIGHTING 345 1968 -6,777.00 2001 33 (223,641.00) 345 1969 -47,623.82 2002 33 (1,571,586.06) 345 1972 -34,326.00 2001 29 (995,454.00) 345 1972 -25,553.00 2001 29 (741,037.00) 345 1974 -11,197.00 1997 23 (257,531.00) 345 1975 -72,000.00 2001 26 (1,872,000.00) 345 1976 -263,382.00 1997 21 (5,531,022.00) 345 1976 -81,648.35 2000 24 (1,959,560.40) 345 1976 -14,236.89 1997 21 (298,974.69) 345 1976 -3,957.40 1997 21 (83,105.40) 345 1977 -25,749.00 1998 21 (540,729.00) 345 1978 -15,000.00 1998 20 (300,000.00) 345 1979 -8,254.00 2000 21 (173,334.00) 345 1980 -30,304.00 2000 20 (606,080.00) 345 1982 -14,030.00 1997 15 (210,450.00) 345 1982 -17,170.00 2001 19 (326,230.00) 345 1984 -14,338.00 1998 14 (200,732.00) 345 1984 -23,047.00 2001 17 (391,799.00) 345 1985 -207,043.00 1998 13 (2,691,559.00) 345 1985 -28,948.00 2001 16 (463,168.00) 345 1994 -18,999.91 2005 11 (208,999.01) 345 1994 -8,667.29 2005 11 (95,340.19) 345 1994 -6,887.96 2005 11 (75,767.56) 345 1995 -98,971.75 2005 10 (989,717.50) 345 1998 -84,499.00 2001 3 (253,497.00) 345 1976 -106,846.70 2003 27 (2,884,860.90) 345 1977 -23,219.49 2004 27 (626,926.23) 345 1976 -12,000.00 2005 29 (348,000.00) 345 1986 -20,399.08 2005 19 (387,582.52) 345 1991 -51,477.43 2005 14 (720,684.02) 345 2001 -50,633.98 2008 7 (354,437.86) 345 2000 -455,746.27 2008 8 (3,645,970.16) 345 1974 -43,275.27 2010 36 (1,557,909.72) 345 2005 -6,000.00 2011 6 (36,000.00) 345 1993 -15,000.00 2011 18 (270,000.00) 345 1998 -30,000.00 2011 13 (390,000.00) 345 1997 -105,000.00 2011 14 (1,470,000.00)

-2,082,208.59 (33,753,685.22) 16.21

Information Request

NTPC GRA 2012/13 and 2013/14


BR.NTPC-15


TOPIC:

Depreciation

REFERENCE:

Appendix A, Page A-44

PREAMBLE:

Amortization accounting is proposed for certain accounts that represent numerous units

of property, but a very small portion of depreciable plant in service.

REQUEST:

a) Please indicate whether Gannett Fleming reviewed the appropriateness of the

amortization periods for the accounts (391 to 399) shown at Page A-44, as part

of the current depreciation study. Provide details of the work that was done.

b) Please provide justification for the proposed amortization periods for each

account set out in page A-44, having regard to peer groups, among other

considerations.

RESPONSE:

(a)

Yes Gannett Fleming reviewed the appropriateness of the amortization periods. The

amortization periods are provided at page A-44 (Page II-36 of the study) were the

recommendations of Gannett Fleming. The recommendations were made based on the

experience of Gannett Fleming, and a review of the policies of NTPC regarding

replacement of general plant items, and industry trends. The amortization periods of all

companies within the peer group are provided in the Attachment BR.NTPC-12(a). The

discussions held between company management and Gannett Fleming specifically

reviewed the recommended amortization periods to ensure conformance to the company

Information Request

NTPC GRA 2012/13 and 2013/14


BR.NTPC-15


policies regarding replacement of items such as computer equipment and software, and

tools and work equipment.

(b)

Account 391.01 – Computer Hardware – The recommendation of a 5 year amortization

period was based on the review of the peer companies where each peer company was

using a 5 year period. It is the experience of Gannett Fleming that the majority of

regulated Canadian utilities are amortizing Computer Hardware over periods of not more

than 5 years and as short as 3 years in the circumstances of laptop computers. The 5

year period was confirmed by NTPC to conform (although longer) to the replacement

policy for laptops and desktops and is reasonable when equipment such as printers and

networking devices are considered.

Account 391.02 – Office Furniture and Equipment – The recommendation of a 15 year

amortization period (which represents a 5 year life extension) was based on the review

of the peer companies where most peer companies are using a 15 year period.

Account 391.03 – Computer Software – The recommendation of a 5 year amortization

period was based on the review of the peer companies where each peer company was

using a 5 year period and the experience of Gannett Fleming. The majority of regulated

Canadian utilities are amortizing Computer Software over a 5 year period. However, it is

noted that some companies have segmented their large enterprise type software

systems and in a few cases are amortizing the larger software over a period of 7 to 10

years. However, these utilities using a longer period for enterprise systems, also usually

separate amortize the upgrades to new releases and versions over a 3 to 5 year period.

As such, a period of 5 years would be comparable to even those same companies.

Account 394.0 Tools, Shop and Garage Equipment – The recommendation of a 15 year

amortization period (which represents a 2 year life extension) was based on the review

of the peer companies where most peer companies are using a 15 year period. The 2

year life extension was confirmed as reasonable by NTPC.

Information Request

NTPC GRA 2012/13 and 2013/14


BR.NTPC-15


Accounts 395.0, 398.0 and 399.0 – The recommended amortization periods for these

three accounts were based on discussions between NTPC and Gannett Fleming. The

recommended periods are generally based on a continuation of the currently used life

estimate.

Information Request

NTPC GRA 2012/13 and 2013/14


BR.NTPC-16


TOPIC:

Depreciation

REFERENCE:

Appendix A; Schedule 2 and Schedule 5.1

PREAMBLE:

The Board wishes to examine the relationship between the plant studied for depreciation

purposes and plant as per the Corporation's financial records.

REQUEST:

a) Please reconcile the 2010/11 gross plant balance of $367.374 million shown in

Schedule 2 of Appendix A with the gross plant balance of $373.691 shown in

Schedule 5.1. Explain all reconciling items.

b) Please reconcile the 2010/11 accumulated depreciation balance of $111.229

million and the accumulated reserve variance total of $37.792 as shown in

Schedule 2 of Appendix A with the accumulated depreciation balance of

$146.040 shown in Schedule 5.1. Explain all reconciling items.

RESPONSE:

(a) and (b)

Please refer to Tables 1 and 2 below, which reconcile the gross plant and accumulated

amortization.

Information Request

NTPC GRA 2012/13 and 2013/14


BR.NTPC-16


Table 1:

Gross Plant Reconciliation ($000s)

2010/11 Gross Plant as per Schedule 5.1 373,691$ A Notes:

Reconciling ItemsLand 5,819 Not amortized

Feasibility Study 5,864 Not included in amortization studyMajor Spare Parts 6,207 Not included in amortization study

Insurance Proceeds (13,139) Not included in amortization studyDisallowed Assets 163 Not included in amortization study

Microturbines FERC 155 298 Uses amortization rate from FERC 121Storage Battery Equipment FERC 363 62 Uses amortization rate from FERC 362

Miscellaneous Power Plant Equipment FERC 335 239 Adjustments erroneously excluded from the amortization study. Gannett Fleming confirmed these minor differences would not materially impact the depreciation study results.

Wind FERC 121 353 Inactive asset not included in amortization study and does not incur amortization expense

Computer Software FERC 391.03 355 Inactive asset not included in amortization study and does not incur amortization expense

Transportation Equipment FERC 392 97 Adjustments erroneously excluded from the amortization study. Gannett Fleming confirmed these minor differences would not materially impact the depreciation study results.

Total 6,317 B

2010/11 Gross Plant as per Amortization Study 367,374$ C=A-B

Information Request

NTPC GRA 2012/13 and 2013/14


BR.NTPC-16


Table 2:

Accumulated Amortization Reconciliation ($000s)

2010/11 Acc Amortization as per Schedule 5.1 146,040$ A Notes:

Reconciling ItemsNegative Salvage 40,831

Land & Land Rights (42)Insurance Proceeds (6,810)

Disallowed Assets 99 Microturbines FERC 155 241 Not included in amortization study.

Storage Battery Equipment FERC 363 238 Not included in amortization study. Wind FERC 121 56 Inactive asset not included in amortization study and does not

incur amortization expenseComputer Software FERC 391.03 201 Inactive asset not included in amortization study and does not

incur amortization expense

Total 34,815 B

2010/11 Accumulated Amortization as per Amortization Study 111,229$ C=A-B

Information Request

NTPC GRA 2012/13 and 2013/14


BR.NTPC-17


TOPIC:

Depreciation

REFERENCE:

Appendix A

PREAMBLE:

Gannett Fleming notes that future amounts required for recovery of costs of removal

may be increased by the pause approach taken in this study, the pause approach is only

being considered by NWTPC for a short period of time, which should mitigate the future

cost implications.

REQUEST:

a) Please identify the period for which the pause approach is being proposed, the

reasons for the pause and the reasons for choosing the particular time period

over which the pause would apply.

b) Please identify the increase in future amounts for cost of removal caused by the

pause approach and provide an estimate of the impact on rates in the first 5

years after the pause approach ends.

RESPONSE:

(a)

The pause approach is currently proposed only for the current GRA, which will have the

effect of maintaining the approach until a next depreciation study is conducted and a

next GRA is held to set new rates. There is no fixed period when this is anticipated to

occur.

The reasons for the incorporation of the pause approach are discussed in the Gannett

Fleming report beginning at page II-33.

Information Request

NTPC GRA 2012/13 and 2013/14


BR.NTPC-17


(b)

Based on the best information available today, the annual provision for salvage required

is approximately $1.5 million. The reason for the pause is to permit the current $20

million surplus to be drawn down. Once this is complete, it is anticipated that the $1.5

million annual accrual to the salvage reserve will need to be incorporated into rates (at a

future GRA). Given the revenue requirement for NTPC is in the order of $100 million, the

impact of the end of the pause approach is anticipated to be a rate pressure of 1.5%.

Please refer to the Corporation’s response to BR.NTPC-11(b).

Information Request

NTPC GRA 2012/13 and 2013/14


BR.NTPC-18


TOPIC:

Depreciation

REFERENCE:

Appendix A, Page A-41

PREAMBLE:

"The pause approach as designed by NWTPC retains the current allocation of the

accumulated depreciation accounts into an account related to the recovery of original

cost and an account related to the recovery of the future costs of retirement. However,

over the test period, there will be no true-up or additional amounts of accumulated funds

for the future costs of retirement. As such, over the test period, actual costs of retirement

will continue to be charged against the reserve for future costs of retirement, but no

revenue requirement provision will be made to the continued funding of the reserve for

costs of retirement."

REQUEST:

a) Please provide continuity schedules for the account related to recovery of the

original cost and for the account related to recovery of future costs showing the

opening balance, additions, retirements, adjustments, salvage and closing

balance from 2008/09 actual to 2013/14.

b) Please provide revised Schedules 1 and 2 using the proposed parameters for

survivor curves and the salvage rates that were determined by Gannett Fleming

for the current study, if any. If Gannett Fleming did not determine salvage rates

for the purposes of the current study please reflect the existing salvage rates for

the purposes of this response. For the purposes of this Schedule, please use the

remaining lives in all cases to calculate the annual provision for true up.

c) Please provide the justification for amortizing reserve differences for accounts

391.01 and 391.03 over 5 years instead of remaining life. Indicate whether this

approach is consistent with accepted depreciation accounting practice.

Information Request

NTPC GRA 2012/13 and 2013/14


BR.NTPC-18


RESPONSE:

(a)

Please refer to Table 1 below.

Table 1:

Continuity Schedule for Depreciation Recovery ($000s)

(b)

Please refer to the Corporation’s response to BR.NTPC-11(b).

(c)

The amortization of accumulated depreciation variances is normally carried out over the

composite remaining life of each account in which a variance of greater than +/- 5%

exists. However, in the circumstance of accounts with short average service life

estimates or amortization periods, the variance can be over-corrected within the test

period, resulting in large swings in the depreciation rate from one depreciation study to

the next. Over the past 10 years, it has become more common to set a minimum period

for the amortization of accumulated depreciation variances. In Alberta, the Alberta

Utilities Commission has approved the minimum period to be equal to a period equal to

the shortest average service life estimate. In the circumstance of the NTPC assets the

2009/10 2010/11 2011/12 2012/13 2013/14Actual Actual Forecast Forecast Forecast

Original Cost 89,922 98,387 105,214 116,100 127,902 Add: Amortization & True-Up 9,617 10,219 10,886 11,802 16,415 Less: Disposals, Transfers and other Adjustments 1,153 3,392 - - 3,948

End of Year 98,387 105,214 116,100 127,902 140,368

Negative Salvage 39,191 39,807 40,826 42,064 42,303 Add: Amortization & True-Up 1,805 1,816 1,888 1,964 - Less: Site Restoration 1,188 797 650 1,725 725

End of Year 39,807 40,826 42,064 42,303 41,578

Total Ending Balance 138,194 146,040 158,164 170,205 181,947 Balance as per Schedule 5.1 138,194 146,040 158,164 170,205 181,947

Information Request

NTPC GRA 2012/13 and 2013/14


BR.NTPC-18


shortest average life estimate is five years. A minimum five year period has also been

used in a number of additional Canadian jurisdictions.

Information Request

NTPC GRA 2012/13 and 2013/14


BR.NTPC-19


TOPIC:

Depreciation and IFRS

REFERENCE:

Appendix D, Page D-2

PREAMBLE:

NTPC states it maintains on its regulated financial statements, a Reserve for Future

removal and Site Restoration and an Asset Retirement Obligations –which is a subset of

the legal obligations for asset retirements captured under the Reserve for Future

Removal and Site Restoration.

NTPC also states it will determine if there are any significant differences between this

level of accounting for depreciation and the componentization (i.e. the need to

separately depreciate each item of PP&E with a cost that is significant in relation to the

total cost of the item) required under IFRS and what impact that level of difference may

have on useful lives and amortization rates for IFRS.

REQUEST:

a) Please compare and contrast the reserve for future removal and site restoration

and asset retirement obligations as reflected in the financial statements with

reserve for future removal and site restoration maintained in the regulatory

books. Please provide the projected balances for the above mentioned accounts

as of March 31, 2014. Identify the main reasons for differences in the above

mentioned accounts as per the financial statements and as per the regulatory

books.

b) Please indicate whether the Gannett Fleming study looked at componentization

in developing its depreciation parameters. If not indicate if or when NTPC

proposes to review the level of plant componentization as may be required by

IFRS and when any resulting changes may be implemented for regulatory

depreciation accounting.

Information Request

NTPC GRA 2012/13 and 2013/14


BR.NTPC-19


RESPONSE:

(a)

For financial statement purposes the Corporation presents the Asset Retirement

Obligations separately from the Reserve for Future Removal and Site Restoration. The

total of these accounts equals the negative salvage value as presented in the

Corporation’s response to BR.NTPC-11(a) and (b) Table 2. Please refer to the

reconciliation for the March 2011 balance in Table 1 below.

Table 1:

Reconciliation of 2011 Negative Salvage ($000s)

The $0.005 million variance is not material.

At this time the Corporation cannot forecast the Asset Retirement Obligations and

Reserve for Future Removal and Site Restoration as the International Accounting

Standards Board is still investigating the possibility of maintaining regulated assets and

liabilities under IFRS.

(b)

Gannett Fleming reviewed the componentization of NTPC to ensure that the

segmentation of the assets reflect an appropriate degree of homogeneity in the average

service life estimation and depreciation rate calculations. The Federal Energy Regulatory

Commission (“FERC”) established a uniform chart of accounts in the early 1900’s that

were developed to provide groupings of homogeneous assets. Following the

development of the FERC chart of accounts, many other North American Regulators

adopted a uniform system of accounts that closely follow (or mimic) the FERC chart of

accounts. The FERC (and other similar charts of account) have been tested on

numerous occasions in regulatory proceeding s since the mid 1900’s, resulting in some

2011 Financial Statements

2011 Negative Salvage

Asset Retirement Obligation 4,674 Reserve for Future Removal and Site Restoration 36,152

40,826 40,831

Information Request

NTPC GRA 2012/13 and 2013/14


BR.NTPC-19


minor modifications and fine tuning. The use of the uniform charts of account prescribe

and define the manner in which regulatory accounting (Group accounting) should be

followed. Gannett Fleming notes that the NTPC chart of accounts very closely follow the

current FERC chart of accounts for regulated electric utilities.

Gannett Fleming has been active in assisting regulated Canadian utilities in the

implementation of the International Financial Reporting Standards (“IFRS”). The IFRS

includes International Accounting Standard (“IAS”) 16, which indicates each asset must

be depreciated over its specific useful life. Gannett Fleming advises that the Accounting

firms have agreed that regulated utilities following a chart of accounts similar to the

FERC chart of accounts require very little additional componentization to comply with

IAS 16.

As part of this assignment, Gannett Fleming did a review of the chart of accounts and

FERC code 391 Office Furniture and Equipment was separated into 3 codes; Computer

Hardware, Office Furniture and Equipment and Computer Software. After this change

Gannett Fleming has concluded that the NTPC chart of accounts is sufficiently

componentized to meet both the IFRS and commonly accepted regulatory requirements.

Information Request

NTPC GRA 2012/13 and 2013/14


BR.NTPC-20


TOPIC:

Non-Electric Revenues

REFERENCE:

Table 4.1

PREAMBLE:

The Board wishes to test the veracity of the non electric revenue forecast.

REQUEST:

a) Please provide a breakout of non electric revenues from 2010/11 to 2013/14.

Explain any variances from year to year.

RESPONSE:

(a)

Please see Table 1 below for the breakout of non-electric revenues.

Table 1:

Non-Electric Revenue ($000s)

Connection Charges 217 83 300 (151) 149 - 149Contract Work 361 94 455 (351) 104 - 104Pole Rental 292 (14) 278 2 280 - 280Heat Revenue 65 22 87 40 127 29 156User Pay Fees 82 22 103 (29) 74 - 74Misc Income 89 (53) 35 (35) 0 - 0GNWT Funding 46 54 100 (100) 0 - 0

Total 1,151 207 1,358 (624) 734 29 763

Year over Year

Change

Year over Year

Change2010/11 Actual

2011/12 Forecast

2012/13 Forecast

2013/14 Forecast

Year over Year

Change

Information Request

NTPC GRA 2012/13 and 2013/14


BR.NTPC-20


The explanations for material variances are provided below.

• Connection charges: Forecasts for the test years are based on 3-year actual

rolling average, which is lower than the 2011/12 forecast.

• Contract work revenue: Contract work revenue forecast was omitted from the

other revenue forecast in error. Other revenue forecast will be updated to include

this revenue in the refilling prior to the hearing.

• Heat revenue: Forecasts for the test years are based on 3-year actual rolling

average, revenue from new customers and rate change for Fort Smith heat

sales.

• Miscellaneous income: This revenue stream is not predictable and not

budgeted.

• GNWT Funding: This is for specific programs that the GNWT has agreed to

fund. There were no signed funding contracts in place when budget was

developed. Related costs were not budgeted.

Information Request

NTPC GRA 2012/13 and 2013/14


BR.NTPC-21


TOPIC:

IFRS and Regulatory Treatment

REFERENCE:

Appendix D, Page D-3

PREAMBLE:

At Page D-3, NTPC States there may be differences identified in accounting for:

1. Overheads

2. Componentization of Assets

3. Major overhauls

4. Gains & losses on disposals

5. Amortization rates and other areas not yet identified.

REQUEST:

a) Please identify the criteria and guiding principles that NTPC used or will use in

determining whether regulatory treatment of any given item would be consistent

with treatment for purposes of financial statements (as in the proposal to adopt

IDC in place of AFUDC) or the regulatory treatment would continue as before

notwithstanding the changes dictated by IFRS for financial statement purposes.

Explain by reference to each of the following:

• Adoption of IDC in place of AFUDC

• Treatment of indirect overheads

• Componentization of assets

• Capitalization of major overhauls

• Capitalization of water licensing costs

Information Request

NTPC GRA 2012/13 and 2013/14


BR.NTPC-21


• Customer contributions

• Effective interest rate method for financing costs

b) Please indicate whether any changes (from existing regulatory treatment) to the

treatment of the items listed in a) are reflected in the 2013/14 test year revenue

requirement. If so, please identify and quantify the amounts applicable to each

change.

c) If NTPC intends to make changes (from existing regulatory treatment) to one or

more items listed in a) and have not reflected such changes in the 2013/14

revenue requirement, please indicate when the changes will be made for

regulatory purposes.

RESPONSE:

(a)

With the transition to IFRS reporting the Corporation elected to maintain the regulatory

recording system as consistent as possible with past practice, and to implement this

through maintain reconciling items between regulatory and IFRS accounting. This

approach allows items that have mutual benefits to Customers and the Corporation to be

retained. For example, as demonstrated in past Board decisions, regulatory accounts

such as the Rate Stabilization Fund have clear rate related benefits. At the same time,

the Corporation wanted to minimize increases to administrative costs for maintaining and

reconciling regulatory accounts.

With respect to the items noted, other than IDC, the Corporation is proposing to retain

the existing practice for ratemaking purposes. This is because there remains

considerable uncertainty as to how precisely these items may be required to be reflected

in the IFRS financial statements, and to provide consistency with longstanding practice

for setting rates. Where IFRS does not permit a consistent treatment for financial

statement purposes, NTPC will maintain a reconciliation of the different statements. At

this time the complexity and amount of effort to maintain these reconciliations is

unknown, but not expected to be prohibitive to this approach.

Information Request

NTPC GRA 2012/13 and 2013/14


BR.NTPC-21


The sole reason for adopting the new regulatory approach to AFUDC/IDC is because,

had the previous AFUDC approach been maintained for regulatory purposes, the

expected level of effort to maintain the reconciliation between the two statements would

have been substantial, as each single capital project would have different values for

regulatory purposes versus IFRS purposes (as they would be loaded with different

interest costs), which NTPC is hoping to avoid.

(b) and (c)

Please refer to the Corporation’s response to BR.NTPC-8(a) and (d).

Information Request

NTPC GRA 2012/13 and 2013/14


BR.NTPC-22


TOPIC:

Rates

REFERENCE:

Section 4.1

PREAMBLE:

Rate changes in this GRA are designed to achieve a level of rates that recover the full

2013/14 Revenue Requirement by the end of a four year transition period (“FullRates”).

During the transition period (2012/13, 2013/14 and 2014/15), rates will fail to achieve the

full Revenue Requirement.

REQUEST:

a) Please explain why NTPC chose to request GNWT subsidy for part of its overall

revenue shortfall during the rates phase in period rather than other possible rate

mitigation options-example: obtaining GNWT subsidy for items that are primarily

outside of NTPC's control such as fuel prices; phasing in the cost of significant

capital additions. Discuss the relative merits of NTPC's chosen approach with

other approaches, from the point of view of preserving management's incentives

for efficiency.

b) Please provide tables similar to Tables 4.4 and 4.5 showing the rate changes for

each of the Zones (Snare Yellowknife, Taltson, Norman Wells and Thermal).

Include in these tables the proposed rate changes due to the rates phase in

proposal for 2014/15 and 2015/16.

c) Please expand Schedule 3.2 to show the Norman Wells Zone. Provide a detailed

cost of service by rate zone to demonstrate what costs were assigned to rate

zones and what costs were allocated. For allocated costs, please provide the

basis of allocation.

Information Request

NTPC GRA 2012/13 and 2013/14


BR.NTPC-22


d) Please indicate whether NTPC anticipates any rate changes other than those

resulting from the rates Phase in proposal, in 2014/15 and 2015/16. If so, please

provide an order of magnitude estimate of such expected changes.

e) Table 4.4 indicates NTPC is targeting a revenue to cost coverage ratio of 104.1%

for hydro areas. In Decision 16-2010 Directive 14, NTPC was directed totarget

100% revenue tocost ratios for each zone and for each rate class within each

zone unlessthere is some other restriction or over-riding rate design principle

thatwould compel moving away from 100%. Please provide NTPC's reasons for

targeting a coverage ratio higher than 100% for any given rate zone.

f) In this Application, NTPC has proposed changes only to the energy component

of rates. Please indicate whether NTPC's intent is to file further information in a

2013/14 Phase II proceeding to look at costs and revenues by rate component

and rate design. If so please indicate when NTPC expects to file this Phase II

application. If not please explain how NTPC expects to address any intra class

cross subsidies arising from maintaining fixed charges (customer charge and

demand charge) at a constant level without regard to cost causation.

g) Please indicate when NTPC is targeting to incorporate Norman Wells into the

Thermal zone. Please discuss the transition plan and the rate impacts for

Norman Wells customers.

h) Please indicate when NTPC is targeting for Government rates to reflect the same

rates by rate zone. Please discuss the transition plan and provide the rate

impacts for Government customers, by community, under this plan.

RESPONSE:

(a)

The government support was committed by the GNWT to achieve the government’s

objectives. The approach adopted, however, is superior to the more targeted type of

options set out in the question, as it provides a comprehensive means to achieve

moderated rate adjustments for all customers with the full rates being in place by year 4

of the transition.

Information Request

NTPC GRA 2012/13 and 2013/14


BR.NTPC-22


(b)

Please see the Corporation’s response to YK.NTPC-18(e).

(c)

With respect to Norman Wells as a rate zone, please see the Corporation’s response to

BR.NTPC-22(g) below.

An expanded Schedule 3.2 is provided in Table 1 and Table 2 below, showing the

specifically assigned costs to each of the zones, plus the common costs allocated to the

zones. Note that in preparing the table, it was identified that a small revision is

necessary to the values in Schedule 3.2 which changes the revenue requirements by

zone by less than 0.1%.

Information Request

NTPC GRA 2012/13 and 2013/14


BR.NTPC-22


Table 1:

2012/13 Forecast Revenue Requirement by Zone ($000s )

LineNo. Snare Taltson Thermal HO/RO Total1 Non-Fuel Operation & Maintenance Expense

2 Salaries and Wages 4,594 1,908 7,174 8,747 22,424

3 Non-Production Fuel and Lubricants 255 50 573 61 9404 Supplies and Services 2,820 1,094 4,292 3,607 11,8125 Travel and Accommodation 239 181 944 848 2,212

6 Total Non-Production Fuel Operation & Maintenance E xpense 7,908 3,234 12,983 13,264 37,388

7 Less: Corporate Donations 0 (1) 0 (107) (108)

8 Total Non-Production Fuel Operation & Maintenance E xpense for GRA 7,908 3,233 12,983 13,157 37,280

9 Production Fuel Expense10 Fuel 321 292 23,932 0 24,54411 Purchased Power 0 0 2,993 0 2,993

12 Total Production Fuel Expense 321 292 26,925 0 27,538

13 Amortization

14 Fixed Asset Amortization (less Customer Contributions) 5,813 1,262 5,175 1,049 13,29815 Amortization of Deferred Charges 576 686 2,624 1,395 5,280

16 Total Amortization Expense 6,389 1,947 7,798 2,443 18,578

17 Total Return on Rate Base 11,495 1,376 4,682 1,558 19,111

18 Total Zone Specific Revenue Requirement 26,112 6,848 52,389 17,158 102,506

Common Cost Allocation by Zone

19 Head Office Cost 8,998 2,873 3,611 15,48220 Corporate Sales Share 58.12% 18.56% 23.32%

21 Hydro Regional Cost 720 230 0 95022 Hydro Sales Share 75.80% 24.20%

23 Thermal Regional Cost 0 0 725 72524 Thermal Sales Share 100.00%

25 Distribution Related HO Adjustment (246) 22 224

26 Total Allocated Common Cost 9,472 3,125 4,560 17,158

27 Total Revenue Requirement 35,584 9,973 56,949 102,506

2012/13 Forecast

Information Request

NTPC GRA 2012/13 and 2013/14


BR.NTPC-22


Table 2:

2013/14 Forecast Revenue Requirement by Zone ($000s )

LineNo. Snare Taltson Thermal HO/RO Total1 Non-Fuel Operation & Maintenance Expense

2 Salaries and Wages 4,732 1,965 7,390 9,405 23,4923 Non-Production Fuel and Lubricants 260 51 585 63 959

4 Supplies and Services 2,876 1,116 4,377 3,679 12,0495 Travel and Accommodation 243 184 958 860 2,245

6 Total Non-Production Fuel Operation & Maintenance E xpense 8,111 3,316 13,310 14,007 38,744

7 Less: Corporate Donations 0 (1) 0 (109) (110)

8 Total Non-Production Fuel Operation & Maintenance E xpense for GRA 8,111 3,315 13,310 13,898 38,634

9 Production Fuel Expense

10 Fuel 320 289 24,292 0 24,90111 Purchased Power 0 0 2,978 0 2,978

12 Total Production Fuel Expense 320 289 27,270 0 27,879

13 Amortization14 Fixed Asset Amortization (less Customer Contributions) 6,278 1,375 6,568 1,726 15,94715 Amortization of Deferred Charges 617 1,103 2,633 1,393 5,747

16 Total Amortization Expense 6,896 2,478 9,200 3,119 21,694

17 Total Return on Rate Base 12,140 1,279 4,309 1,609 19,337

18 Total Zone Specific Revenue Requirement 27,466 7,363 54,090 18,626 107,544

Common Cost Allocation by Zone

19 Head Office Cost 9,790 3,096 3,992 16,87820 Corporate Sales Share 58.00% 18.34% 23.65%

21 Hydro Regional Cost 745 235 0 98022 Hydro Sales Share 75.97% 24.03%

23 Thermal Regional Cost 0 0 768 76824 Thermal Sales Share 100.00%

25 Distribution Related HO Adjustment (246) 20 226

26 Total Allocated Common Cost 10,288 3,351 4,986 18,626

27 Total Revenue Requirement 37,754 10,714 59,076 107,544

2013/14 Forecast

Information Request

NTPC GRA 2012/13 and 2013/14


BR.NTPC-22


(d) and (e)

This response has been prepared to address a number of interrogatories which are

referred here from other IRs, and as such extends somewhat beyond the specific scope

contained in the question.

NTPC’s approach to the current GRA has been constructed based on the following key

principles:

1. Rate Changes Are Required Today: Rate increases are required to help bring

rates towards the full revenue requirement.

2. GNWT Support: The GNWT has committed financial support, with specific

conditions, to help transition customers to these new rate levels over an

extended period (4 years).

3. Avoid Future “Rate Cliffs”: Rates put in place today and in the future should be

developed to help avoid future rate cliffs, where major rate changes are needed

at a future date.

4. Simplified Regulatory Process: Rate proposals should permit progression

towards a lower cost and simplified regulatory system.

5. Benefit Customers: It is in the customer’s interests to have rate proposals that

are simple to understand, reflect gradualism in rate changes, and are fair across

the zones.

NTPC’s GRA filing achieves the above objectives in a single package, with no need for a

segregated “Phase I” and “Phase II” process.

Specifically, the GRA achieves the following outcomes:

• Adopt a simplified rate design that shares cost inc reases across-the-board:

This approach is consistent with the principles of the GNWT funding and is

consistent with recent practice in many Canadian jurisdictions, as set out in

YK.NTPC-18(d). This approach also does not get distracted with excessive

analysis on specific components of the rates (such as tweaking demand charges)

Information Request

NTPC GRA 2012/13 and 2013/14


BR.NTPC-22


but focuses on the energy component, which is the component best understood

by customers and provides the best signals for conservation.

• Rates well below costs in the test years: Due to the magnitude of the GNWT

funding available, all zones will be paying well below the pure costs to serve

them in the test years 2012/13 and 2013/14. Please also see YK.NTPC-18(c).

• Rates at or below costs over the full 4 years of tr ansition: Over the full 4 year

transition, even with the proposed sequential rate increases each year, each

zone will be at or below the costs to serve them (Snare at 100.1%, Thermal at

87.5%, Taltson at 79.9%, when including only modest assumed cost inflation in

2014/15 and 2015/16). Please see YK.NTPC-18(c).

• No need for second hearing to complete GRA: The rate proposals contained

in the GRA, along with detailed zonal cost allocation, provide all necessary

information for the Board to conclude that the rate proposals meet the

requirements of the Public Utilities Act (i.e., that rates are just and reasonable).

Customers also benefit from the avoidance of a costly second process (Phase II)

just to complete the GRA.

• Not defer problems into the future: The four year transition covers a period

where NTPC has no plans for material further revenue requirement increases

and no expectations of new rate pressures to arise, outside possible fuel price

increases. As a result, the rate transitions required by 2015/16 and beyond are

expected, based on the best available information, to be similarly managed on a

gradual basis. This can only occur, however, if cost and rate issues that arise are

addressed promptly, including: (a) keeping up on fuel price changes (see below),

(b) amortization rates that properly reflect the Corporation’s asset lives are

implemented (see Appendix A of the Application), and (c) new rate cliffs are not

created by excessively deferring costs or advancing benefits of known events (for

example, gradually drawing down the approximately $20 million net salvage

surplus, as proposed by the Corporation, rather than some more drastic

approach).

• Fuel prices must be carefully tracked and incorpora ted into rates promptly:

Issues of rate cliffs can arise outside of GRAs when fuel costs are deferred and

built up, rather than being built into riders/rates promptly. While accrued or

deferred RSF balances can be amortized over varying periods, including longer

periods of time, to help defer these rate impacts, the most effective way to avoid

Information Request

NTPC GRA 2012/13 and 2013/14


BR.NTPC-22


rate impacts from deferred RSF balances is to avoid the balances in the first

place, to the largest extent possible. This includes such measures as

implementing fuel riders where “keep up” fuel prices have risen, even though

“catch up” deferred RSF balances have not yet hit the defined triggers. The

recent GNWT “due diligence” process review strongly recommends that fuel

riders be implemented routinely, frequently and with minimal regulatory process,

to ensure this can be achieved and rate cliffs can be avoided.

In short, given the challenging rate situations that face customers today, with higher fuel

prices, the end of gas supply in Inuvik, the need to invest in aging infrastructure like

Bluefish, and other compounding rate drivers, the NTPC GRA is a practical and

streamlined approach that achieves a wide range of very important objectives. It can be

implemented with an efficient regulatory process, in a manner that is understandable to

customers and that is not unfair to any zone. No second GRA “phase” is required.

(f)

Please see the Corporation’s response to BR.NTPC-22(d) and (e) above.

The setting of customer charges and demand charges in NWT does not require a cost of

service study. It has been the longstanding practice in NWT that these amounts are

primarily set based on considerations of affordability and rate impacts on customers

(particularly smaller customers), as well as consistency between utilities and

communities. These amounts have never been set based on pure costs since Phase II

Cost of Service studies started being prepared in the early 1990s. Because these

amounts are set below costs, the resulting energy rates are set somewhat above the

pure cost level to make up for the difference. This is a reasonable outcome for a number

of reasons:

1. To NTPC’s knowledge, no power utility sets customer charges to fully recover the

customer–related costs measured in a cost of service study, for the same

reasons of affordability and impacts on small customers that are used in NWT.

2. The customer charge is an unavoidable part of a power bill, whereas energy

usage can be managed. As a result, a somewhat higher energy charge permits

the customer to better manage and reduce their power bills than if these same

Information Request

NTPC GRA 2012/13 and 2013/14


BR.NTPC-22


amounts were charged via the fixed customer charge. This helps encourage

conservation.

3. A significant portion of the general service demand charges function in the exact

same manner as a customer charge (i.e., a minimum amount equal to $40 is

charged each month, and is unavoidable for the customer), particularly for

smaller GS customers.

For example, in the 2001/03 GRA, the cost of service study indicated that residential

customer charges, based on pure cost analysis, would have to be in the range of

$50/month to $150/month to fully recover the customer-related charges (with somewhat

lower energy rates being set). This approach to setting rates would not be practical. In

that GRA, the customer charge was retained at $18/month.

In short, there is no need for a fully functionalized, classified and allocated cost of

service study to determine the proper rate designs for these components. The rates

proposed by NTPC maintain consistency with fixed rates in place prior to the GRA, are

largely the same as the residential customer charge used by NUL (YK) and NUL (NWT),

and remain a reasonable assignment of the fixed costs of the system to each customer.

(g)

Norman Wells is being treated in this application as fully part of the Thermal zone. For

example, the Norman Wells assets do not earn a Return on Equity and Norman Wells

costs are combined with the other Thermal zone communities for all calculations. The

only distinction between Norman Wells and the rest of the Thermal zone is that Norman

Wells has a different (lower) rate for the time being, until rate transition plans can be

confirmed and developed. One such plan was set out in the GRA (15%/year increases

on energy rates, until the community rates reach the Thermal zone level), but

alternatives are now under review.

(h)

NTPC has not developed any specific transition plan for government rates to be moved,

on a revenue-neutral basis, to a levelized structure. This is because the customers who

pay these rates almost entirely represent either direct or indirect purchases by the

Information Request

NTPC GRA 2012/13 and 2013/14


BR.NTPC-22

June 8, 2012 Page 10 of 10

GNWT (with the results being equal and offsetting among the various communities). For

the purposes of this application, the focus has been on dealing with other material rate

pressures that required GNWT attention (notably the major funding being committed

from GNWT), and as a result the GNWT as the customer for these sales has not

indicated a desire to restructure their rates in the manner noted.

Information Request

NTPC GRA 2012/13 and 2013/14


BR.NTPC-23


TOPIC:

Deferral Accounts

REFERENCE:

Section 5.5

PREAMBLE:

The Board wishes to test the principles and assumptions used for deferral accounts.

REQUEST:

a) Please provide the criteria NTPC uses to determine whether a particular item of

expense should be given deferral account treatment as opposed to the utility

assuming the forecast risk.

b) Please provide the criteria NTPC uses to determine whether a particular item of

expense should be given deferred cost treatment whereby the deferred amount

is amortized over a number of years into the future. Please describe the criteria

used to determine the amortization period and indicate whether one of the

considerations in designing the annual amortization is to zero out the deferral

account at the end of the amortization period.

c) Please expand the deferral account continuity provided in Schedule 5.5 to

include 2007/08 to 2009/10. For the PUB and other deferral accounts provide the

continuity information by expense component for all years. Include an additional

column for actual information for 2011/12.

d) Please provide a Schedule showing the calculation of the amortization amounts

in each of the two test years for each of the deferral accounts shown in Schedule

5.5.

e) Schedule 5.5 indicates annual appropriations under a number of deferral

accounts were insufficient to cover the expenditures for a number of years.

Information Request

NTPC GRA 2012/13 and 2013/14


BR.NTPC-23


Please explain why NTPC did not adjust the annual appropriations in the 2008/09

to 2011/12 period to more closely reflect the expenditure levels. Alternatively,

please explain why NTPC did not put forward a GRA. Discuss the implications of

the significant accumulation of deferred balances for inter generational equity.

f) NTPC states other deferred costs include various studies and assignments that

the Corporation undertakes that have benefits spanning more than one year.

These projects are amortized over a number of years to reflect the term of the

benefits expected to be derived from the expenditure. Please indicate whether

NTPC requested approval for deferral treatment of other deferred costs. If not,

explain why deferral of these costs does not constitute retroactive rate making.

g) With respect to the overhaul deferral account, please compare the annual keep

up provision that was approved at the last GRA for overhauls by zone with the

annual actual expenditures, from 2007/08 to 2011/12. Provide reasons for any

significant variances between the annual keep up provision and annual

expenditures.

h) With respect to the overhaul deferral account, please provide a detailed schedule

showing how the keep up provision for the test years was determined. Describe

all assumptions used for this calculation.

i) NTPC states higher than expected overhaul costs for the gas units in Inuvik is

driving the need for an increase in the Thermal zone amortization. Please

describe the timing and nature of the gas unit overhaul expenses and indicate

whether NTPC could have taken steps to mitigate such expenses given the

knowledge NTPC will be switching to diesel in Inuvik in 2012/13.

j) With respect to the water licensing deferral account, please compare the annual

keep up provision by zone that was approved at the last GRA with the annual

actual expenditures, from 2007/08 to 2011/12. Provide reasons for significant

variances.

k) Having regard to the information provided in Table 5.7, please provide details of

how the keep up provision for the test years was determined with respect to the

water licensing deferral account. Describe all assumptions used for this

Information Request

NTPC GRA 2012/13 and 2013/14


BR.NTPC-23


calculation. Provide support including assumptions used for all forecast

expenditures.

l) With respect to charges to the reserve for injuries and damages, please provide

details of the incidents for each of the years 2007/08 to 2011/12 and explain why

these are considered appropriate charges against the reserve.

m) With respect to the employee future benefits account, please provide a continuity

schedule showing the drawdown of previously set aside amounts completed in

2008/09 resulting in a balance of $1.972 million as of year end 2011/12. Provide

details of how the keep up portion of this item was determined including details of

all assumptions used in the forecast.

n) Since NTPC is requesting a brushing deferral account as part of this GRA,

please explain why 2012/13 opening balance is not a zero balance.

o) At Page 6-25, NTPC states, in the intervening 5 years since the previous GRA,

NTPC has spent an average of $333,000 on brushing annually. Starting in

2011/12, NTPC has adopted an annual target of $441,000 per year as a new

stabilized annual level of spending. Please provide the line Kilo meters of

brushing and unit costs for each of the years 2007/08 to 2011/12 and the

forecasts for 2012/13 and 2013/14. Provide reasons for any changes in the line

Kilo meters of brushing for the test period compared with the average for the

previous 5 years. Also provide the assumptions used to forecast unit costs in the

test years.

RESPONSE:

(a) and (b)

Each of the items presently established with deferred cost treatment have either been

previously reviewed by the Board, or have been established based on the rationale set

out by NTPC in past GRAs and consistently applied by NTPC and by the Board.

Information Request

NTPC GRA 2012/13 and 2013/14


BR.NTPC-23


For example, the Board adopted specific principles to be applied for deferred costs in

Decision 17-2007, as follows:

“The Board considers deferred cost items may typically include financing

costs and any material costs incurred in conducting special studies. In

order for such expenditures to be considered eligible, NTPC should be

able to demonstrate corresponding benefits that extend beyond a single

year. Further, for deferred cost items that arise in non-test years the

quantum of the expenditure proposed for deferred cost treatment should

be material and NTPC should demonstrate why they are not considered

part of the forecast variance in operations and maintenance expenses in

that year. In future proceedings, NTPC is directed to provide evidence

showing how each item proposed for deferred cost treatment meets the

conditions outlined above.”

No new rules or principles are being proposed in this GRA, retroactively or otherwise. It

is normal practice that deferred items are reviewed by the Board in each Rate

Application, such as referenced in Board Decision 13-2007 (e.g., the approval of the Job

Evaluation Reviews, at page 123 of Decision 13-2007).

It has been NTPC’s longstanding practice (and typically regulated utility practice),

including at the 2006/08 GRA, that where the Corporation makes expenditures and

determines that expenditure results in an intangible asset (no physical asset results) that

benefits more than one year, the Corporation will defer and amortize these costs.

Appropriate deferred costs have to meet the following tests:

1. There is a benefit to the Corporation and its Customers of more than one year,

and

2. The expenditure is not covered in the Corporation’s current revenue requirement.

Items qualifying for deferred cost treatment will be amortized over a five year period or a

more applicable term if one can be demonstrated by applying a matching test of benefit

duration to amortization period. This precise approach to deferral accounting was set out

in the Corporation’s response to Decision 13-2007, in NTPC’s October 1, 2007 refiling.

The Board reviewed and accepted this approach in Decision 17-2007, as noted above.

Information Request

NTPC GRA 2012/13 and 2013/14


BR.NTPC-23


The Corporation’s approach to deferral is not premised on having to wait for a GRA to

apply appropriate regulatory accounting practices. In particular, when a cost arises that

meets the Corporation’s tests as set out above, that item is deferred (as a deferred cost)

and amortization is initiated. New additions to deferral costs provide benefits that extend

beyond a single year (e.g., IFRS conversion, Enterprise Resource Planning).

The amortization or recovery period for those expenses is based on the estimated life of

the project, estimated benefit period or for catch up portions, a reasonable time period

for both Customers and the Corporation. In this regard, deferred costs are precisely like

fixed assets that are constructed and capitalized in each year (whether a test year or not

a test year) with appropriate lives matching the benefits that the asset provides.

For deferred costs (e.g., brushing expenses for each year, IFRS conversion and

Enterprise Resource Planning) at the end of the amortization period the balance will

equal $0, by definition, as the amortization rate is designed to lead to this precise result.

For items that are in a permanent deferral account (e.g., Reserve for Injuries and

Damages, the Rate Stabilization Funds, the Water Licencing Account, the Overhaul

account, the Employee Future Benefits net balancing account), the balances will be

targeted to $0 over time, but the precise schedule to reach or maintain $0 varies by

account.

(c)

Please refer to Table 1 below. The 2011/12 year-end audit is currently being finalized

and audited results are not available. There was a $0.011 million adjustment in the

calculation of Regulatory deferrals for the 2011/12 forecast year which will be corrected

when schedules are produced for the Hearing.

Information Request

NTPC GRA 2012/13 and 2013/14


BR.NTPC-23


Table 1:

Deferral Accounts Continuity Schedule ($000s)

Please refer to Table 2 below illustrating the Regulatory and Other Deferral account by

expense component.

2007/08 2008/09 2009/10 2010/11 2011/12 2012/13 2013/14Actual Actual Actual Actual Forecast Forecast Forecast

Add: Regulatory & Other DeferralBeginning of Year 1,383 1,749 1,576 1,222 900 1,185 1,921 Additions 1,038 500 282 306 912 1,113 - Amortization 672 673 636 627 627 377 376 End of Year 1,749 1,576 1,222 900 1,185 1,921 1,545

Mid-Year Balance 1,566 1,663 1,399 1,061 1,043 1,553 1,733

Add: Overhaul DeferralBeginning of Year (1,187) -968 611 1,889 3,584 4,032 2,582 Additions 1,913 3,272 2,971 3,388 2,141 1,596 2,847 Amortization 1,693 1,693 1,693 1,693 1,693 3,046 3,046 End of Year (968) 611 1,889 3,584 4,032 2,582 2,383

Mid-Year Balance (1,078) (179) 1,250 2,736 3,808 3,307 2,483

Add: Water Licensing DeferralBeginning of Year 600 704 949 1,083 1,397 5,099 5,118 Additions 241 382 270 451 3,838 771 943 Amortization 137 137 137 137 137 751 1,175 End of Year 704 949 1,083 1,397 5,099 5,118 4,885

Mid-Year Balance 652 827 1,016 1,240 3,248 5,109 5,002

Add: Reserve for Injuries & Damages DeferralBeginning of Year 2,597 3,029 2,547 2,589 2,861 2,191 1,521 Additions 1,102 188 712 942 - - - Amortization 670 670 670 670 670 670 670 End of Year 3,029 2,547 2,589 2,861 2,191 1,521 851

Mid-Year Balance 2,813 2,788 2,568 2,725 2,526 1,856 1,186

Add: Employee Benefits DeferralBeginning of Year (485) (27) 260 379 1,668 2,276 2,182 Additions 458 287 119 1,289 608 255 134 Amortization - - - - - 348 348 End of Year (27) 260 379 1,668 2,276 2,182 1,969

Mid-Year Balance (256) 116 319 1,023 1,972 2,229 2,076

Add: Brushing DeferralBeginning of Year 397 750 Additions 441 441 441 Amortization 44 88 132 End of Year 397 750 1,059

Mid-Year Balance 199 573 904

Total Mid-Year Regulatory Accounts 3,697 5,215 6,552 8,786 12,795 14,627 13,384

Information Request

NTPC GRA 2012/13 and 2013/14


BR.NTPC-23


Table 2:

Regulatory Deferral Account & Other Deferral Costs Continuity Schedule ($000s)

Regulatory Hearing Costs

Taltson Excess

CapacityElectroflow

StudyJob

Evaluation

Net Billing Demonstration

ProjectWebsite Design

IFRS Conversion

115KV transmission

Line Study

Snare Infrastructure

Study

Enterprise Resource Planning Total

Balance @ March 2007 1,231 5 27 121 1,383 Additions/Deletions 1,038 1,038 Amortization 600 2 9 61 672

Balance @ March 2008 1,668 2 18 61 1,749 Additions/Deletions 365 64 26 45 500 Amortization 600 2 9 61 1 673

Balance @ March 2009 1,433 - 9 - 63 26 45 1,576 Additions/Deletions 83 - 199 - - 282 Amortization 600 9 13 5 9 636

Balance @ March 2010 916 - 50 199 20 36 1,222 Additions/Deletions 200 97 297 Amortization 600 13 5 9 627

Balance @ March 2011 515 9 38 296 15 27 900 Additions/Deletions 499 26 - 250 - - 136 912 Amortization 600 13 5 9 627

Balance @ March 2012 415 35 25 546 10 18 136 1,185 Additions/Deletions 800 5 308 1,113 Amortization 243 8 13 55 5 9 44 377

Balance @ March 2013 972 32 12 492 5 9 400 1,921 Additions/DeletionsAmortization 243 8 12 55 5 9 44 376

Balance @ March 2014 729 24 - 437 - - 355 1,545

Information Request

NTPC GRA 2012/13 and 2013/14


BR.NTPC-23


Calculation of Amortization:

When a deferred cost project is completed, all costs are recovered over a period of 5

years except for Enterprise Resource Planning and IFRS Conversion which have a 10

year recovery period.

(d)

Please refer to BR.NTPC-23(c) for the Regulatory and Other amortization schedule and

collection periods.

The Reserve for Injuries and Damages annual amortization is left unchanged from the

previous Board approved amount.

For overhaul deferrals see Table 3 below.

Table 3:

Amortization Calculation – Overhaul Deferral ($000s )

Catch Up2012 Balance 4,032 Collection Period (years) 10

Catch Up amortization 403

Keep Up - Snare ZoneTotal additions from 2007-2014 2,539 Annual Average (7 years) 363

Keep Up - Taltson ZoneTotal additions from 2007-2014 1,514 Annual Average (7 years) 216

Keep Up - Thermal ZoneTotal additions excluding Inuvik 2007-2014 6,926 Total additions Inuvik 2007-2014 7,519 Total additions 2007-2014 14,445 Annual Average (7 years) 2,064

Total 3,046

Information Request

NTPC GRA 2012/13 and 2013/14


BR.NTPC-23


Due to the change in Inuvik generation the keep up portion for the Thermal zone was

split between all communities excluding Inuvik and the community of Inuvik. At the time

of this Application the specific engine configuration, type and maintenance schedules

were unknown and the Corporation could not forecast overhaul expenses with any

certainty. As a result the forecast values from 2012 to 2014 were based on a gas diesel

overhaul configuration before the change in generation source was determined.

Water licence deferrals are set out in Table 4, showing the composition of costs in the

account and the calculations supporting the annual level of appropriation. In practice,

this same appropriation to the account will occur each year until next adjusted by the

Board regardless as to the actual spending on each item noted in Table 4.

Information Request

NTPC GRA 2012/13 and 2013/14


BR.NTPC-23

June 8, 2012 Page 10 of 25

Table 4:

Amortization Calculation – Water Licence Deferral ( $000s)

Total

2012 Balance

Years Remaining On Licence

Catch Up Amortization

Dam Crest

Surveys

Water Flow

Monitoring

Aquatic Effects

Monitoring Program

Water Licence Renewal

Years Remaining On Licence

Water Licence

Amortized Cost

Dam Safety Review

Life of Dam

Safety Review

Dam Safety Review

Amortized Cost Total Keep Up

Catch Up and Keep

UpA B C=A/B D E F G H I=G/H J K L=J/K M=D+E+F+I+L N=C+M

2012/13 Test Year

Taltson Zone 4,334 15 289 10 134 - 120 15 8 - - - 152 441 Snare Zone

Bluefish Licence 175 9 19 10 82 - 50 8 6 - - - 98 118 Snare Licence 591 12 49 30 95 - 200 11 18 - - - 143 192

358 50 311 - 32 - 393 751

2013/14 Test Year

Taltson Zone 4,334 15 289 10 134 400 120 15 8 - - - 552 841 Snare Zone

Bluefish Licence 175 9 19 10 82 - 50 8 6 95 4 24 122 141 Snare Licence 591 12 49 30 95 200 11 18 - - - 143 192

358 50 311 400 32 24 817 1,175

Catch Up Annual Keep Up Amortized keep Up

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June 8, 2012 Page 11 of 25

Details on the Employee Future Benefits amortization are set out in Table 5.

Table 5:

Amortization Calculation – Employee Future Benefits Deferral ($000s)

The keep up portion of the employee future benefits account was estimated at $0.120

million per year using an estimated number of employees retiring in each Test Year

multiplied by the average net liability per employee outstanding. The estimated number

of retirements was determined by recent actual retirement history combined with the

estimated employee retirements for the Test Years.

Table 6:

Amortization Calculation – Brushing Deferral ($000s )

(e)

Please refer to the Corporation’s response to TGC.NTPC-8(b) as to why a GRA has not

been filed since the 2007/08 year.

With respect to adjustments to deferral accounts, it has been NTPC’s practice to adjust

these accounts at each GRA, and to attempt to set the appropriation levels so that they

can smooth out year-to-year fluctuations between GRA years. NTPC was not aware that

the Board would entertain or encourage adjustments to the deferral accounts outside of

Catch Up2012 Balance 2,276 Collection Period (years) 10

Catch Up amortization 228

Keep Up 120

Total 348

Total Cost

Amortization (years) 2012/13 2013/14

2011/12 Brushing Program 441 10 44 44 2012/13 Brushing Program 441 10 44 44 2013/14 Brushing Program 441 10 44

88 132

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June 8, 2012 Page 12 of 25

GRA test years. Such a practice could be considered in future if the Board indicated its

willingness to regulate on this basis. However, there would remain a need to ensure that

rate or rider changes were not made to address a short-term anomaly that would

otherwise work itself out over the longer-term (as is the general intent of these

accounts).

As per the Corporation’s response to BR.NTPC-23(a) and (b) above, all charges to a

reserve must be consistent with clear principles, which have been supported by the

Board in past GRAs. Charges to the water licence deferral are amortized over the life of

the existing licence ensuring costs match the benefit received by customers. The

Employee Benefits Deferral was established in the 2001/03 GRA at the request of the

customers and now requires an annual appropriation in accordance with the 2001/03

Negotiated Settlement. In the 2006/08 GRA the Overhaul Deferral account was tracking

well and only a small adjustment was required. However as discussed in response

BR.NTPC-23(g) below, higher than anticipated costs from 2007 to 2011 in the Thermal

zone has placed upward pressure on the balances.

(f)

Please refer to the Corporation’s response to BR.NTPC-23(a) and (b).

(g)

Table 7 below shows the overhaul continuity schedule from 2007/08 actuals to 2011/12

forecast.

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BR.NTPC-23

June 8, 2012 Page 13 of 25

Table 7:

Overhaul Continuity Schedule by Zone ($000s)

The Thermal zone balance of $5.1 million is driven by higher than anticipated overhaul

costs in Inuvik, Tuktoyaktuk and Fort Good Hope.

Inuvik

In the 2006/08 GRA the Corporation did not adjust the annual amortization expense for

the community of Inuvik. The $0.380 million annual amortization has been in place since

the overhaul deferral account was first established by the Board in the 2001/03 GRA. In

the 2006/08 GRA the third natural gas engine for the community of Inuvik was added to

rate base, but the annual amortization provision was not adjusted for the additional

engine as the overhaul account was generally tracking well (the Corporation did include

an overhaul forecast for the third natural gas engine). Table 8 shows the variance due to

the engine installation and the variance due to market pricing.

2007/08 2008/09 2009/10 2010/11 2011/12Actual Actual Actual Actual Forecast

Taltson ZoneBeginning of Year (208) (175) (116) (140) (12)

Additions 160 186 103 256 197 Amortization 127 127 127 127 127

End of Year (175) (116) (140) (12) 58

Snare ZoneBeginning of Year (60) (393) (822) (1,162) (1,065)

Additions 138 42 131 569 377 Amortization 471 471 471 471 471

End of Year (393) (822) (1,162) (1,065) (1,159)

Thermal ZoneBeginning of Year (919) (400) 1,549 3,191 4,660

Additions 1,614 3,044 2,738 2,564 1,567 Amortization 1,095 1,095 1,095 1,095 1,095

End of Year (400) 1,549 3,191 4,660 5,133

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June 8, 2012 Page 14 of 25

Table 8:

Inuvik Overhaul Variance Analysis ($000s)

In December 1999 the Corporation signed a ten year maintenance agreement with the

Original Equipment Manufacturer (OEM) for the two natural gas generating units. The

maintenance agreement resulted from the installation of the two natural gas units in

1999. The price paid for services under the maintenance agreement was based on the

power production subject to a 4% annual escalation with a minimum annual price. The

price included the OEM’s fees, cost, profits, overheads including shipping and removal

of parts, replacement of parts and procurement of parts. Based on the terms of the

contract, if the OEM failed to satisfy the maintenance requirements the contract could be

terminated. However neither party would be liable to one another after the termination

date.

In July 2007 the Corporation terminated the maintenance contract due to poor

performance and service. Overhauls were not being completed in a timely fashion

resulting in increased down time and the Corporation was experiencing premature failure

of external components such as lube pumps decreasing the running time of the engines.

The contract had benefits for the Corporation and ultimately for Customers due to the

pricing terms of the contract. From 2004 to 2007 the Corporation met with the OEM on

several occasions and tried to resolve the issues but it became apparent the level of

service was not going to improve. Even though the pricing terms of the contract were

beneficial, the Corporation could not continue to reduce the reliability of the engines and

the contract was terminated.

2007/08 2008/09 2009/10 2010/11 2011/12Actual Actual Actual Actual Forecast Total

AdditionsThird Gas Engine 29 645 212 687 83 1,655 A

Original Gas Engines 839 566 938 876 349 3,568 BDiesel Engines 5 231 343 - - 579 CTotal Additions 873 1,441 1,493 1,563 432 5,802 D=A+B+C

Amortization 380 380 380 380 380 1,900 E

Variance due to 3rd Gas Engine 29 645 212 687 83 1,655 F=AVariance due to Market Pricing 464 417 901 496 31- 2,246 G=(B+C)-E

Total Variance 493 1,061 1,113 1,183 52 3,902 H=F+G

Information Request

NTPC GRA 2012/13 and 2013/14


BR.NTPC-23

June 8, 2012 Page 15 of 25

After the contract was terminated the Corporation was required to use market prices

resulting in higher costs. From 2001 to 2006 before the contract was cancelled the

average annual overhaul cost was $0.322 million1. From 2007 to 2012 after the contract

was cancelled the annual average overhaul cost for the original gas engines was $.714

million, $0.392 million higher than the previous 5 years.

Tuktoyaktuk & Fort Good Hope

In 2003/04 the Corporation signed an engine maintenance program with the OEM for the

maintenance of 3500 series Caterpillar diesel engines. The program was based on a

22,000 hour equipment management strategy that would expire after the engines

reached the end of the 22,000 hour life cycle. The OEM would complete preventative

maintenance, top end overhauls and major overhauls at predetermined hour levels and

the Corporation would complete routine maintenance. The pricing included all labour and

materials but the Corporation was responsible for travel costs, consumables and freight

costs.

On average the engines in the two communities reached the end of the life cycle in

2008/09 and the contract was completed. The Corporation received a renewal offer

however similar to other price increases faced by the Corporation during that time the

total proposed contract increased by more than 120%. Given the price increase the

Corporation did not extend the contract. From this point the Corporation paid market

prices for materials and labour which was similar to the pricing presented by the OEM

but offered the Corporation greater flexibility to manage overhaul schedules. Table 9

below shows the variance to these two communities from 2007/08 to 2011/12.

Table 9:

Overhaul Schedule for Tuktoyaktuk and Fort Good Hop e ($000s)

1 The Corporation’s response to TGC.NTPC-53 from the 2006/08 GRA.

2007/08 2008/09 2009/10 2010/11 2011/12Actual Actual Actual Actual Forecast Total

Additions 389 654 197 277 465 1,982 Amortization 120 120 120 120 120 600

Variance 269 534 77 157 345 1,382

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BR.NTPC-23

June 8, 2012 Page 16 of 25

From 2003 to 2008 while on the OEM contract the average annual overhaul cost for the

two communities was $0.234 million1. From 2008/09 to 2011/12 after the contract was

completed the annual average overhaul cost for the two communities was $0.398

million, $0.164 million higher.

(h)

Please refer to the Corporation’s response to BR.NTPC-23(d) above.

(i)

The majority of the increased overhaul costs occurred from 2007 to 2011 before the

Corporation was notified of the natural gas shortage in Inuvik. As noted in the

Corporation’s response to TGC.NTPC-11(a) the Corporation was not notified of the gas

shortage until late 2011/12.

(j)

Table 10 below compares the actual/forecast additions to the 2006/08 Board approved

amortization.

1 The Corporation’s response to TGC.NTPC-53 from the 2006/08 GRA.

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June 8, 2012 Page 17 of 25

Table 10:

Water License Additions to Board Approved Amortizat ion ($000s)

As background, the $0.137 million was estimated in the 2006/08 GRA as a first attempt

at pegging the long-term average annual cost of securing and maintaining water

licences. Given the increasing scale of regulation faced by NTPC for water licence

renewals, this amount has proven to be materially insufficient.

As the $0.137 million annual appropriation was a long-term average estimate (not a

typical “keep up” provision), and was not a forecast of specific annual spending, it is not

possible to compare forecasts to actuals. However, the largest components of spending

that have been charged to the account are as follows:

Annual Water Monitoring Costs - $1.1 million over 5 years:

As a typical condition of NTPC’s Water Licences and necessary for economic water

dispatch, the Corporation must receive and provide accurate hydrologic information. The

Corporation has an agreement with Environment Canada for the operation and

maintenance of eleven hydrometric stations (water level and/or flow) located in the

Snare River basin area, Taltson River basin, Yellowknife River basin and the associated

data processing and reporting; and

2011/12 Taltson Relicensing - $3.2 million:

In June 2011 the Corporation filed a water licence renewal application with the

Mackenzie Valley Land and Water Board (“MVLWB”). The Corporation applied for a

renewed licence which would allow the Taltson hydro facility to continue to produce

hydroelectric power. In support of that application the Corporation filed numerous

environmental and social economic impact studies.

2007/08 Actual

2008/09 Actual

2009/10 Actual

2010/11 Actual

2011/12 Forecast Total

Additions 241 382 270 451 3,838 5,182Amortization 137 137 137 137 137 683Variance 104 246 133 315 3,702 4,499

Information Request

NTPC GRA 2012/13 and 2013/14


BR.NTPC-23

June 8, 2012 Page 18 of 25

In the June 2011 water licence application the Corporation stated the following:

The original facility was built in the 1960’s and no baseline data were

collected from Taltson River, Nonacho Lake or Trudel Creek in regard to

the project development at that time.

Under the current water licence, a Water Effects Monitoring Program

(WEMP) was developed with the objective of providing efficient and

effective identification of short-term, long‐term and cumulative changes

throughout the Taltson River aquatic environment. From 2006 to 2010, a

series of environmental baseline studies were conducted in support of the

potential expansion of the existing Twin Gorges Hydroelectric Generating

Station. The Taltson Hydroelectric Expansion Project (Expansion Project)

proposed to add a new 56 MW power plant to the existing 18 MW Twin

Gorge facility and interlink the expanded generation facility through a new

transmission line to supply hydropower to several developed mines and a

proposed mine. It has been recognized by NTPC and Expansion Project

partners that the 1999 TOR for the WEMP for Twin Gorges, and the

environmental baseline study programs for the proposed Taltson

Expansion Project had overlapping interests. Therefore, Expansion

Project baseline studies are being used by NTPC to address the intent of

the current WEMP TOR and have application in the updated TOR

associated with the licence renewal.

The following list outlines studies undertaken to date in association with

the facility and/or Taltson River. Study maps are included in the reports.

• Cambria Gordon Ltd. 2007. Trudel Creek August 2007 Fish and

Fish Habitat Data Report. Prepared for the Dezé Energy

Corporation.

• Cambria Gordon Ltd. 2008. Littoral Habitat Assessment of

Nonacho Lake, Lady Gray Lake and Trudel Creek. Prepared for

the Dezé Energy Corporation.

• Dezé Energy Corporation. 2009. Taltson Hydroelectric Expansion

Project Developers Assessment Report.

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BR.NTPC-23

June 8, 2012 Page 19 of 25

• FSC. 1999. Water Effects Monitoring Program – Taltson Hydro

Project Northwest Territories. Prepared for the Northwest

Territories Power Corporation, Hay River, by Ferguson Simek

Clark. Yellowknife, North/South Consultants Inc., Winnipeg and

Trillium Engineering and Hydrographics, Edmonton.

• Golder. 2006. Wildlife and Wildlife Habitat Studies along the

Taltson Expansion Project. Prepared by Golder Associates Ltd. for

the Northwest Territories Energy Corporation. Yellowknife, NT.

• Golder. 2007. Autumn and Early Winter Wildlife Surveys, Taltson

Expansion Project. Prepared by Golder Associates Ltd. for the

Northwest Territories Energy Corporation. Yellowknife, NT.

• Klohn Crippen Berger. 2009. Trudel Creek Erosion Assessment.

Prepared for the Northwest Territories Energy Corporation.

• Mitchelmore Engineering Company Ltd. 2011. 2010 Dam Safety

Review Program Taltson Hydroelectric Development: Prepared for

the Northwest Territories Power Corporation by Mitchelmore

Engineering Company Ltd. 2011.

• Rescan Environmental Services Ltd. 2000. Water Effects

Monitoring Program Aerial Beaver Survey. Yellowknife, NT:

Prepared for the Northwest Territories Power Corporation by

Rescan Environmental Services Ltd.

• Rescan Environmental Services Ltd. 2001. Water Effects

Monitoring Program Aerial Muskrat Survey. Yellowknife, NT:



• Rescan Environmental Services Ltd. 2001. Taltson Hydro Project

Meteorology and Hydrology Compilation Data Report. Prepared

for the Northwest Territories Power Corporation by Rescan

Environmental Services Ltd.


2003: Water Effects Monitoring Program. Vancouver, BC:



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BR.NTPC-23

June 8, 2012 Page 20 of 25

• Rescan. 2003. Taltson Hydroelectric Expansion Project, 2003

Baseline Report. Northwest Territories Power Corporation.


2004: Water Effects Monitoring Program. Vancouver, BC:




2006: Terms of Reference Review. Prepared for the Northwest

Territories Power Corporation.

• Rescan Environmental Services Ltd. 2006. Taltson River Basin

Model for Proposed Power Plant Upgrades. Prepared for the

Northwest Territories Power Corporation by Rescan

Environmental Services Ltd.

• Rescan. 2006. Taltson Expansion Project Trudel Creek Fish and

Fish Habitat Assessment. Northwest Territories Energy

Corporation.

• Rescan. 2006. Taltson Hydro Project: Trudel Creek Hydrological

Assessment. Prepared for Dezé Energy Corporation by Rescan

Environmental Services Ltd. October 2006.

• Rescan. 2008. Final Report and Northern Pike Spawning and

Rearing Habitat in Trudel Creek. Northwest Territories Energy

Corporation.

• Rescan. 2008. 2008 Taltson Basin Wildlife Baseline Report.

September 2008. Prepared for Deze Energy Corporation.

• Rescan. 2008. Taltson Wetlands Baseline Studies Report: 2008.

Unpublished report to Deze Energy Corporation by Rescan

Environmental Services Ltd., Vancouver, B.C.

• Rescan. 2008. Trudel Creek Aquatics Baseline Report 2008.

Prepared for the Northwest Power Corporation by Rescan

Environmental Services Ltd. October, 2008.

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BR.NTPC-23

June 8, 2012 Page 21 of 25

Although the Taltson Water Licence requirements and filing were undertakings well

beyond the scale anticipated by NTPC, the process has been successful to date. Also of

note, a substantial number of the studies listed above were funded by other parties

(government contributions made to Deze, NTEC03) and used to the benefit of

ratepayers at no direct cost to customers.

In addition, the Taltson account includes a small amount of compensation paid in

respect of other water users, as it is a required part of the Water Board licencing

process. As noted in the GRA page 1-9, substantial additional compensation had been

claimed. The Water Board has now indicated that it would support the awarding of only

1% of the compensation claimed. Final regulatory decisions on this matter remains

outstanding pending the Minister approving the Water Board’s findings. No amounts

have been charged to the account for this additional compensation.

(k)

Please refer to the Corporation’s response to BR.NTPC-23(d).

(l)

Table 11 below shows all the charges to the reserve from 2007/08 to 2011/12.

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BR.NTPC-23

June 8, 2012 Page 22 of 25

Table 11:

RFID Charges 2007/08 to 2011/12 ($000s)

(m)

Please refer to Table 5 above for the amortization calculation.

Table 12 shows the continuity schedule for Employee Future Benefits from 2007/08 to

2013/14.

Zone Loss Description Event Description Amount

Thermal G10 Generator Failure

The Inuvik G10 generator overheated and had mechanical failure. The incident was claimed under the Corporation's insurance program. Amount charged to RFID is the insurance deductible and self retention amounts. 229

Hydro Jackfish Oil Spill Cleanup Final close out costs from a fuel spill at the Jackfish Generating Station. Reviewed and approved in the 2006/08 GRA. 100

HydroSnare Forks Channel Mitigation

Dam breach at Snare forks. Reviewed and approved in the 2006/08 GRA. Insurance claim filed with insurers and the outcome is being negotiated. 972

HydroPenstock Excessive Ice Build Up

The Bluefish intake tunnel developed excessive ice and water seepage. The ice was removed and the water leakage issue fixed. 358

Thermal Engine Failure Catastrophic engine failure in Wha Ti. Insurable event but below the insurance deductible. 71

HydroTransmission Line forest fire

Forest fire between Taltson and Fort Smith damaged transmission lines. Below insurance deductible and transmission lines are excluded from coverage. 110

Hydro Bearing Failure

A bearing failed on the Taltson hydro generator. The incident was claimed under the Corporation's insurance program. Amount changed to RFID is the insurance deductible and self retention amounts. 455

Thermal EMD Turbo FailureTurbocharger failure on the Inuvik EMD diesel engine. This was an insurable event but below the insurance deductible. 143

Thermal G6 Electrical Over Voltage

A spike in voltage from a standby generator in Inuvik damaged auxiliary electrical and plant equipment. This was an insurable event but below the insurance deductible. 290

ThermalAugust Plant Lightning Strike

Lightning struck the Norman Wells standby plant destroying auxiliary electrical equipment. Insurable event but below the insurance deductible. 216

2,944

Information Request

NTPC GRA 2012/13 and 2013/14


BR.NTPC-23

June 8, 2012 Page 23 of 25

Table 12:

Continuity Schedule Employee Future Benefits ($000s )

Table 13 below reconciles the regulatory employee future benefit year-end calculation to

the accounting calculation in the Corporation’s financial statements.

Table 13:

Employee Future Benefits Reconciliation ($000s)

An "addition" represents a cash payment to an employee or for the benefit of an

employee when they retire or resign in accordance with their employment contract

and/or terms under the collective agreement. Additions are classified as:

a) A resignation benefit for employees hired prior to April 1, 1995.

b) A retirement benefit for employees who reach age 55 and entitled to allowance

under the Public Service Superannuation Act.

c) Ultimate removal benefit to return employee to their original place of hire.

2007/08 2008/09 2009/10 2010/11 2011/12 2012/13 2013/14Actual Actual Actual Actual Forecast Forecast Forecast

Employee Future BenefitsBeginning of Year (485) (27) 260 379 1,668 2,276 2,182

Additions 458 287 119 1,289 608 255 134 Amortization - - - - - (348) (348) End of Year (27) 260 379 1,668 2,276 2,182 1,969

Mid-Year Balance (256) 116 319 1,023 1,972 2,229 2,076

2007/08 Actual

2008/09 Actual

2009/10 Actual

2010/11 Actual

Employee Future Benefits Asset 2,323 3,165 3,602 3,788 Employee Future Benefits Liability 2,350 2,905 3,223 2,120 Net Employee Future Benefits (27) 260 379 1,668

Regulated Employee Future Benefits (27) 260 379 1,668

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June 8, 2012 Page 24 of 25

Due to contractual obligations and employee confidentiality a description of all events

cannot be provided. The deferral account moved from a negative position to positive in

2008/09 as benefits were paid to employees. Termination benefits referred to in the

Application on page 5-14, L4-10 are the additions referred to above.

(n)

With respect to deferrals in years prior to the GRA, NTPC’s proposed approach to

brushing as set out in Section 5.5 of the Application is identical in practice to the

development of the Water Licencing Deferral Account in the 2006/08 GRA, which

similarly had an “opening balance” in the first test year (2006/07). This approach was

accepted by the Board in Decision 13-2007 at Section 7.3.2.

The reason the brushing deferral has unamortized amounts is that NTPC began the

practice of deferring brushing expenses in 2011/12, prior to the current GRA, when it

became apparent that this was the appropriate regulatory accounting approach for these

expenses. See BR.NTPC-23(a) for a discussion of the appropriate use of deferral

accounting (deferred costs) for NTPC.

The topic of brushing was a material item of review in the 2006/08 GRA, and the subject

of a special Review and Variance proceeding. The Board indicated in Decision 13-2007

that “As there is no evidence to the contrary, the Board accepts NTPC’s argument that

the forecast expenditures of $393,000 for 2006/07 and $401,000 for 2007/08 represent

the necessary, normalized level of brushing on a go-forward basis”, however in Decision

4-2008 the Board reduced the forecast brushing expenses to $126,000 and $129,000 for

2006/07 and 2007/08 respectively to reflect the average of past practice. Consequently,

the 2010/11 and 2011/12 brushing program expenses, which were in excess of

$400,000, reflect costs that were of a multi-year benefit and were not included in NTPC’s

revenue requirement and thus met the test for deferral accounting.

In hindsight, NTPC could arguably have initiated this deferred cost approach in 2010/11

given the magnitude and approach that the brushing program began to target in that

year ($0.441 million – materially beyond the $0.129 million scale adopted by the Board

in Decision 4-2008), however in practice the 2010/11 brushing spending was expensed,

and the 10 year amortization approach was only adopted in 2011/12.

Information Request

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BR.NTPC-23

June 8, 2012 Page 25 of 25

(o)

It is not possible to provide the total kilometres of line brushed or the unit cost per

kilometre of NTPC’s brushing program. In most cases, the Corporation performs

scattered brushing of key “danger trees” or other areas of high priority rather than

brushing pre-defined sections of transmission or distribution lines. Further, the

Corporation utilizes a number of different brushing methods which range from large

industrial mowers to manual cutting with chainsaws. As such, a unit cost per kilometre

would vary significantly between regions and situations. Please refer to the Corporation’s

response to TGC.NTPC-44(a) for a summary of NTPC’s actual brushing costs. The

amount proposed for the brushing deferral account is reasonable as it is a representative

of actual amounts spent on brushing over the last four years and is a reasonable

expectation of NTPC’s brushing requirements for the Test Years.

Information Request

NTPC GRA 2012/13 and 2013/14


BR.NTPC-24


TOPIC:

Affiliate Transactions

REFERENCE:

Table 6.7

PREAMBLE:

The Board wishes to understand the methods used to calculate charges to affiliates.

REQUEST:

a) Please expand Table 6.7 to include 2012/13 and 2013/14.

b) Please describe the nature of work that is done for non regulated affiliates that

attracts overhead charges. Explain how overhead costs applicable to work

performed for non regulated affiliates are tracked.

c) Provide a detailed calculation showing how the overhead charged to non

regulated affiliates was calculated for 2010/11 and 2011/12 actuals and 2012/13

and 2013/14 forecasts.

RESPONSE:

(a)

Please refer to Table 1, a revised version of Table 6.7 in the Application, below.

Information Request

NTPC GRA 2012/13 and 2013/14


BR.NTPC-24


Table 1:

Affiliate Actual Costs 2007/08 to 2010/11 and Forecasts 2011/12 to 2013/14 ($000s)

Note:

1. Actual transactions from April 2011 to December 2011 shown.

The reduction of overhead costs in Table 1 for the years 2011/12 and onwards reflects

the substantial reduction in activity for NTPC’s affiliated companies, with the suspension

of the Taltson Expansion, and the smaller scale and revised focus of those affiliates on

assessing small alternative energy options.

(b)

The majority of affiliate transactions require very little resources to manage throughout

the year and therefore do not have material overhead costs directly assigned to them.

The Corporation allocates overhead costs to recover time spent on affiliate matters that

are not directly assigned such as purchasing and logistic matters, HR support, IT

support and accounting assistance. All of which would include management time to

supervise such activities. The costs for affiliate transactions are tracked with separate

plant numbers and therefore are readily separated from regulated activities and not

included in the Corporation’s revenue requirement.

(c)

For 2010/11, 2011/12 and 2012/13, overhead costs are budgeted annually by the

Corporation as part of its regular O&M budgeting process. Managers prepare ‘bottom-

up’ overhead budgets in light of the work expected to be carried out for NTPC’s non-

regulated affiliates in the coming year. These budgeted amounts are reflected in Table 2

below. An assumed inflation factor of 2% over 2012/13 amounts was used to calculated

the 2013/14 budgeted overhead costs.

Transaction Description 2007/08 2008/09 2009/10 2010/11 2011/121 2012/13 2013/14NTPC Direct Costs 235 216 213 283 193 228 233 NTPC Utility Bills 17 17 12 8 7 9 9 Overhead Costs 150 150 150 116 87 74 75 Shared Services 60 62 98 144 106 161 164 Interest Expense 492 342 185 227 164 133 136

Dividends declared to non-regulated entities 800 850 800 825 500 400 400 Dividends paid to non-regulated entities - 1,271 1,163 812 402 400 400

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NTPC GRA 2012/13 and 2013/14


BR.NTPC-24


Table 2:

Affiliate Overhead Budgets by Department ($000s)

2010/11 Actual

2011/12 Forecast

2012/13 Forecast

2013/14 Forecast

Management Services 37.7 28.3 20.0 20.4 Accounting Services 2.0 1.5 25.0 25.5

Engineering 34.5 25.9 9.0 9.2 HR Services 5.0 3.8 5.0 5.1 IT Services 36.6 27.5 15.0 15.3

115.8 86.9 74.0 75.5

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BR.NTPC-26


TOPIC:

Deferral Accounts

REFERENCE:

Response to Directive 5 from Decision 17-2007

PREAMBLE:

The Board wishes to test the need for the new deferral accounts.

REQUEST:

a) Please explain why brushing, IFRS expenditures and enterprise resource

planning should receive deferral account treatment.

b) Please provide a break out of the forecast cost for IFRS implementation and

demonstrate why the forecast is prudent and reasonable.

c) Please identify the nature of improvement to NTPC’s financial systems that are

expected to provide long-term benefits. Please provide evidence to demonstrate

the forecast cost of $444,000 is prudent and reasonable.

RESPONSE:

(a)

Please refer to part (c) below and the Corporation’s response to BR.NTPC-23(a).

(b)

Please refer to Table 1 below for the IFRS forecast costs by expense category for the

years 2009/10 to 2011/12. As IFRS transition is now expected to occur after a 12 month

delay, there remain IFRS costs to be spent in the test years. These costs were not

included in the GRA estimates.

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NTPC GRA 2012/13 and 2013/14


BR.NTPC-26


Table 1:

IFRS Forecast costs by Expense Category ($000s)

The costs were required as the Corporation transitions to IFRS. The Corporation was

required to use external consultants that specialize in transitioning utility companies into

IFRS. In 2009 the Corporation reviewed IFRS transition costs from other Canadian

electric utilities. Table 2 below compares the transition costs from 11 Canadian electric

utilities. The average cost for conversion was estimated at $1.59 million, $1 million

higher than the Corporation’s estimate at the time of the Application.

Table 2:

Estimated IFRS Conversion Costs ($ millions) compared to Rate Base ($000s)

from Canadian Electric Utilities

(c)

In keeping with NTPC’s commitment to continuous improvement, in 2010/11 a project

was initiated to review the Great Plains system which is the core of NTPC’s Enterprise

Resource Planning (ERP) system. The objective was to assess whether opportunities

exist to optimize the system and increase effectiveness and efficiency throughout the

Corporation.

The first phase of the project, which was completed in 2011/12, was a gap analysis of

the building blocks in NTPC’s ERP (e.g. general accounting, customer processing,

2009/10 2010/11 2011/12Actual Forecast Total

Salary & Wages 1 1 Consultants 291 250 541

Travel & Accommodation 4 4 296 250 546

Conversion Cost

Rate Base Value

Minimum 0.40 155,700 Maximum 8.00 12,500,000 Average 1.59 5,061,254

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NTPC GRA 2012/13 and 2013/14


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procure to pay/supply chain, human resources/payroll, projects and operations) against

leading practice and common utility practice. Gaps were assessed in terms of system

limitations, need for process improvement and training. The first phase also identified

opportunities for improving integration between the modules that comprise the ERP and

to identify and work to eliminate a number of manual processes that are time consuming

and may lead to errors or duplication of effort.

The second phase of the project which will be completed in 2012/13 will focus on

organizational hierarchy and code block structure. These two elements are fundamental

to a fully functioning ERP system as they are the foundation of the system and key to the

integration of the various modules. This phase will also assist with transition into IFRS to

ensure the ERP can accommodate both IFRS and rate regulated accounting.

The budget of $444,000 includes both the first and second phase and is primarily related

to consulting services. The prudency of this cost is supported by the gap analysis which

identified a number of areas where NTPC’s ERP is not functioning in a manner

consistent with common utility practice. As well a number of manual processes were

identified that could be reduced or eliminated. The budget, of which $136,000 was spent

in 2011/12 is reasonable given the current scope of the project however since the GRA

was filed, it has been identified that a Business Intelligence (BI) tool would be a valuable

addition in terms of maximizing the reporting capabilities of the system. A capital project

for 2012/13 will be identified, estimated and managed within the overall capital budget

put forward in the GRA for 2012/13. Any future improvements to the ERP will be

assessed in terms of cost/benefit and the treatment of those expenses as current or

deferred costs will be made in accordance with the principles established in the 2006/08

GRA. Please see the Corporation’s response to BR.NTPC-23(a) and (b) for the

approach to deferred costs.

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NTPC GRA 2012/13 and 2013/14


BR.NTPC-27


TOPIC:

Terms and Conditions (T&C) of Service

REFERENCE:

Page 7-2

PREAMBLE:

NTPC is proposing changes to Section 5.11 of the T&Cs. The proposal states "At the

effective date all unclaimed security deposits which are older than 6 years immediately

become the property of the Corporation."

REQUEST:

a) Please identify the amount of security deposits that are older than 6 years as of

yearend 2011/12. Identify the reasons why such deposits are remaining

unclaimed.

b) Please indicate whether, under NTPC's current procedures, customers are

required to request refund of their deposits when they terminate service or after

they have established satisfactory credit. If so indicate whether the unclaimed

security deposits are the result of customers failing to make such requests.

c) Please indicate whether refunds of security deposits can be made automatically

by NTPC as and when customers terminate service or when they establish

satisfactory credit.

RESPONSE:

(a)


referred here from other IRs, and as such extends somewhat beyond the specific scope

contained in the question.

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NTPC GRA 2012/13 and 2013/14


BR.NTPC-27


The Corporation is currently finalizing its 2011/12 year-end audit and actual information

is not available for this period. Please refer to Table 1 below, which summarizes the

amount of unclaimed security deposits that are older than six years as of March 31,

2011. The unclaimed security deposits in this schedule represent amounts abandoned

by customers after service has been terminated, and all amounts owing on their account

have been fully covered. Often when service is terminated by customers, the forwarding

contact information provided is incomplete or incorrect. This makes refunding the

unclaimed portion of the security deposit difficult as the Corporation has no way to

contact the customer. In situations when the forwarding information is incorrect, the

Corporation’s customer service staff will attempt to contact the customer by phone or by

use of ‘local knowledge’ to locate the customer and complete the security deposit refund.

If these efforts to contact the customer are unsuccessful, under the present Terms and

Conditions, the Corporation is presently in the position of having to maintain records of

the deposit indefinitely, which is inconsistent with the Corporation’s practices for limiting

the retention of customer data. Presently, for privacy and logistical reasons, the

Corporation only retains customer data on closed accounts for a maximum of seven

years.

Although the amount of unclaimed security deposits at March 31, 2011 is small, these

amounts are expected to be higher beyond the six year window illustrated for March 31,

2011. The balance of unclaimed security deposits has accrued as a liability for the

Corporation and needs to be dealt with.

Table 1:

Unclaimed Security Deposits Older than 6 Years

Effective Date Annual Amount Cumulative Amount

March 31, 2009 $272.24 -

March 31, 2010 $117.24 $389.48

March 31, 2011 $1,492.76 $1,882.24

Total Number of Unclaimed Security Deposits 26

(b) and (c)

As per Section 5.9 and 5.10 of NTPC’s Terms and Conditions of Service, security

deposits are refunded after 1 year of good credit history or when the customer is

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BR.NTPC-27


disconnected from service other than for default in payment of accounts. Security

deposits are returned to customers by way of a credit to their account. In situations when

a customer is disconnected from service other than for default in payment of accounts,

the Corporation applies all or a portion of the customer’s security deposit, including

interest, toward the payment of any amount due and owing by the customer. Often, this

practice leaves a residual amount of the security deposit available to be refunded to the

customer by way of cheque. The unclaimed security deposits referred to in the proposed

Section 5.11 are a result of customers abandoning the residual amounts of the security

deposit after it has been applied to their final bill upon termination of service.

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NTPC GRA 2012/13 and 2013/14


BR.NTPC-28


TOPIC:

Gross Plant and Capital Additions

REFERENCE:

Appendix B

PREAMBLE:

The Board wishes to test the historical and test year forecasts for capital additions.

REQUEST:

a) Please identify the cost of any heat recovery plant and corresponding

contributions included in rate base for each of the test years.

b) Please provide the schedules comparable to B1 to B4 for capital additions in

2007/08 forecast, 2007/08 actual, 2008/09 actual and 2009/2010 actual.

c) Please compare the capital budgets for the following items with the actual costs

and provide explanations for variances:

Schedule B.1-Snare Zone:

Snare Rapids Plant Upgrade

Bluefish Power Tunnel Upgrade

Bechchoko Plant Assessment Planning Study

Replace Upgrade IT Equipment

Schedule B.1-Taltson Zone:

Construct Winter Road

Schedule B.1-Thermal Zone:

Fuel System Upgrade-Tuktoyaktuk

Increase Fuel storage capacity

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NTPC GRA 2012/13 and 2013/14


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Schedule B.1-Corporate Head Office:

Replace Upgrade IT Equipment


Packaged Sewage Treatment System



Relocate Standby D&F Tanks


Genset Replacement-D398

Genset Replacement-D379

Inuvik Tank Farm Study

Distribution System Voltage Conversion Upgrade

New Warehouse

New Office Building

Ft Liard Heat Recovery & DHS

Schedule B.2-Corporate Head Office:

Non Recoverable Type 6 Work

Small Demand Capital Projects

With respect to each project, please describe the budgeting and approval

process and explain how accountability and control over costs was maintained

during project execution and commissioning.

d) With respect to the Bluefish dam and Phase 2 detailed engineering as well as the

Bluefish dam and spillway projects shown in Schedule B-3, please provide i) the

expected commissioning date ii) the budgeted percent completion as per the

project schedule prepared at the time of the budget estimates as of year end

2010/11, 2011/12 and 2012/13 and the actual/forecast project completion

percent as of the same year ends iii) the budgeted and actual/forecast costs that

are associated with the respective completion percentages referred to in ii)

above. Provide explanations for significant variances.

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e) With respect to the Inuvik diesel engines project ($8 million) shown in schedule

B-3, please provide a detailed budget and identify the key assumptions used to

arrive at the budget. Provide a cost per KW comparison for the installed cost of

the Inuvik units as compared to similar projects at other locations.

f) Please provide a detailed analysis of the design options considered by NTPC

when the decision was made to replace gas units with diesel units at Inuvik.

Indicate whether consideration was given to any economies by virtue of the

potential for reusing certain existing infrastructure such as switchgear.

g) Please indicate whether the gas units at Inuvik are to be retired or disposed of. If

so indicate whether any gain or loss on sale is included in the revenue

requirement.

h) With respect to the Snare Jackfish system transient stability upgrade project

shown in Schedule B-4 ($3.3 million), please provide a detailed budget and

identify the key assumptions used to arrive at the budget. Please identify the

alternatives considered and explain why this particular alternative was chosen.

i) With respect to the distribution system upgrade project ($1.3 million) shown in

Schedule B-4, please provide a detailed budget and identify the key assumptions

used to arrive at the budget. Please identify the alternatives considered and

explain why this particular alternative was chosen.

j) At Page 1-3 NTPC states rather than replacing plants, NTPC has worked to

utilize existing assets or upgraded existing plants to meet current service

requirements where possible. Please provide examples of where NTPC has

implemented such initiatives.

RESPONSE:

(a)

Please refer to the Corporation’s response to TGC.NTPC-49(g) regarding government

contributions. The amount of capital additions for the 2011/12 fiscal year is $2.195

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NTPC GRA 2012/13 and 2013/14


BR.NTPC-28


million for the Fort Liard Heat Recovery & DHS system in the Thermal zone. There are

no additional capital projects in the test years.

(b)

Please refer to the Attachment BR.NTPC-28(b) 1 - 4 for capital additions in 2007/08

forecast, 2007/08 actual, 2008/09 actual and 2009/10 actual.

(c)

Variance analysis is provided for the capital projects listed in Schedule B.1. Variance

analysis cannot be provided for capital projects listed in Schedule B.2 as the Corporation

is currently finalizing its 2011/12 yearend audit and actual information is not available.

Please refer to the Corporation’s response to YK/HR.NTPC-29(a) for the Corporation’s

capital budgeting process. On a monthly basis the Corporation produces a report of the

current capital costs which compares period and year-to-date actual results with budget.

If required project monitors will complete and submit a ‘job cost revision’ for Senior

Management to review and approve. Please refer to the Corporation’s response to

YK/HR.NTPC-29(g) for further information.



Original Budget: $0.658 million

Final Cost: $1.434 million


referred here from other IR’s and as such extends somewhat beyond the specific scope

contained in the question. This response specifically addresses the capital additions

completed in 2010/11.

With respect to business case assessment, please see YK.NTPC-29(b). The rationale

for the Snare Rapids Plant Upgrade is to update end-of-life equipment at one of the

Corporation’s key hydro sites, as set out in the Snare Rapids project permit application

before the Board in 2004.

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NTPC GRA 2012/13 and 2013/14


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The work completed in 2010/11 consisted of constructing a new headgate building and

installing a new headgate hoist. The original headgate design from 1948 did not allow

the headgate to be fully removed from the water for inspection. Standard industry

designs include headgates that can be removed for inspection. Maintenance inspections

were completed under water using divers. This technique is inferior to a visual dry

inspection as items such as cracks and rust buildup are more difficult to notice. A new

taller headgate building was required to lift the headgate entirely out of the water for

inspection. This work formed part of the major project permit approved by the Board.

The variance relates to higher than budgeted contract costs due to current economic

conditions, delays from other projects, automatic dispatch operation and change in

methodology to construct the building.

The work was delayed by one year due to conflict with another project at the same site.

The installation of two new Transformers at Snare Rapids was expected to be completed

in early summer and then the headgate hoist project would start in late July and be

completed that same summer. The Transformer project was not completed until the end

of summer and there is insufficient capacity at the Snare camp for the number of

workers required.

Due to economic conditions the proposals received for the work was higher than

originally budgeted. The Corporation initiated an invitational request for proposals

(RFPs) with seven qualified contractors for the construction of the headgate hoist. Four

proposals were received and the lowest cost proposal was accepted. The Corporation

initiated an invitational tender with eight qualified contractors for the construction of the

headgate building. Two bids were received, both were higher than budgeted and the

lowest cost was accepted.

The building construction was completed using a crane on site with a ‘man basket’. This

allowed workers to be suspended over the river and they were tied to the boom in

accordance with industry safety standards. The extra costs associated with the operation

of the crane were not originally budgeted.

The scope of the project was also changed to allow remote operation of the headgate.

Historically in the event of an over-speed situation the plant operator was required to

lower the headgate at the Snare Rapids plant. By connecting the headgate to the

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NTPC GRA 2012/13 and 2013/14


BR.NTPC-28


SCADA system the headgate can be lowered remotely from the central control center at

Jackfish.

Bluefish Power Tunnel Upgrade



After the tunnel was dewatered leakage at the headgate was noticed and the

Corporation revised the project scope to include a tunnel inspection and a bulkhead and

rock stability study.

Behchoko Plant Assessment Planning Study



The Corporation received four proposals from qualified consultants to conduct a plant

assessment study at Behchoko. All of the proposals had higher costs than originally

budgeted.

Replace/Upgrade IT Equipment


Total Spend: $0.275 million

Please refer to the Corporation’s response to YK/HR.NTPC-30(f) for procedures on

replacing IT equipment.

The variance relates to the early deployment of server virtualization infrastructure. The

deployment of the virtualization hardware was originally budgeted for 2011/12 but was

completed in 2010/11.


Construct Winter Road

Please refer to the Corporation’s response to NUL.NTPC-3.

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NTPC GRA 2012/13 and 2013/14


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Fuel System Upgrade – Tuktoyaktuk



The fuel tanks in Tuktoyaktuk are required to be in compliance with Underwriting

Laboratories of Canada (ULC) standards and the National Fire Code (NFC). An

inspection of the Tuktoyaktuk tanks indicated various upgrades to the tank farm were

required to meet the necessary standards.

The initial budget was based on the installation of two new top draw double walled

90,000 litre tanks to replace the bottom feed tanks. The tanks were purchased in

2006/07 and the work commenced in 2007/08. The cost variance for the installation of

the tanks is $0.300 million related to higher than forecast market prices for equipment

rentals and contractors plus transportation costs for fuel deliveries. When the fuel

system was being reconfigured delivery by fuel truck was required to the plant day tank.

The fuel delivery costs were not originally forecast. During final installation in 2007/08

the Corporation experienced a number of pumping issues related to the new tanks and

frequent outages would occur due to fuel starvation. Subsequent investigation and

engineering design indicated new submersible fuel pumps were required. Costs from

2008/09 to 2010/11 related to engineering design, material purchases such as pumps

and piping, overheads and AFUDC.

Increase Fuel Storage Capacity


Total Spend: $0.707 million

The fuel tanks in Fort Liard are required to be in compliance with all applicable

standards. An inspection of the Fort Liard tanks indicated various upgrades to the tank

farm were required to meet the necessary standards.

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NTPC GRA 2012/13 and 2013/14


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The original budget was based on installing a new 45,000 liter double walled tank beside

the existing 45,000 liter single walled tank and berm while, tying into the existing piping.

The work description was modified as the exiting pad and berm limited yard access, the

piping did not meet code and one 90,000 litre double walled tank was the preferred

option. A new granular pad was built to accommodate the 90,000 litre double walled tank

and to improve yard access. The deficient piping was replaced and rerouted to the new

tank location and the pre-existing pad and berm were removed.

(d)

Please refer to the Corporation’s response to YK/HR.NTPC-19 and 21.

(e) and (f)

The total cost of converting the Inuvik plant to a prime power diesel operation is set out

in the GRA at $11.5 million at page 2-5 based on estimates then available. This included

$8 million for the power plant (2012/13), plus a total $3.5 million for recommissioning

diesel fuel storage at Tank F ($2.3 million in 2012/13 and $1.2 million in 2013/14). The

recommissioning of Tank F was under consideration for future years even absent the

conversion of Inuvik to diesel, but must now be advanced to permit a baseload diesel

operation.

The Inuvik conversion project is being undertaken entirely in response to the termination

of natural gas availability for NTPC use, as set out in TGC.NTPC-11. This project is

being pursued on a necessarily expedited schedule to respond to unforecast conditions.

As a result, there remains significant detail to be addressed before the final plans and

budgets can be fully confirmed.

At this time, the project originally estimated at $8 million for plant conversion project is

expected to be completed in two parts:

1. Project #1: Locate Additional 2.5 MW EMD in Inuvik - $2.6 million: At

present, NTPC maintains only a backup diesel plant in Inuvik, consisting primarily

of 2 - 1970’s vintage EMD gensets, of 2.5 MW each, plus a small 720 kW genset.

Consistent with the approved RFC criteria, this plant can supply peak winter

loads in Inuvik (if the gas supply is off) only if all 3 diesel units are in service. For

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NTPC GRA 2012/13 and 2013/14


BR.NTPC-28


now, if one or more of the units are out of service, NTPC must rely on temporary

supplemental generation from natural gas. In order to transition to a baseload

diesel plant, and to permit Project #2 to be completed, the 720 kW genset will be

replaced with a 2.5 MW EMD in NTPC’s Inventory. This project will proceed as

soon as possible, for a targeted fall completion. The project costs are shown in

Table 1 below.

2. Project #2: Convert 2 Wartsila gas engines to diese l – estimated at $7.7

million: In order to complete NTPC’s transition to a baseload diesel system,

starting in fall 2012, two of the three Wartsila gas engines will be converted to

operate on diesel. This project remains in the estimating stages, and once plans

are firmed up, will be the subject of a Major Project Permit under section 54 of

the Public Utilities Act.

Table 1:

Costs of Project #1 – Locate 2.5 MW EMD in Inuvik ( $000s)

Based on the above project breakdown, the $8 million estimate in the GRA is now

expected to exceed $10 million for the engine component of the Inuvik conversion.

(g)

Please refer to response (e) and (f) above and TGC.NTPC-12(c).

Cost Item CostMaterial 1,250Shipping 100Labour (includes hotels & Travel) 300

Consultants 130Site supervision 100Contingency 400Overhead @ 12% 274

Sub-total 2,554

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June 8, 2012 Page 10 of 20

(h)

The Snare system is comprised of 4 hydro plants on the Snare River, 2 hydro plants on

the Yellowknife River and the Jackfish diesel plant located in Yellowknife. Currently the

system provides electrical generation to the communities of Yellowknife, Behchoko and

Dettah and two industrial customers. Historically the load was largely influenced by

mining loads with high load factors. During this time diesel generation supplemented the

base load hydro units. Diesel generation is faster responding and so was able to

minimize any stability problems caused by the slower responding hydro units. Now that

Yellowknife is almost 100% hydro generation, tight control of frequency has become

much more difficult utilizing the older electro-mechanical governor technology on the

hydro units. This technology is essentially unchanged from the 1940’s – 1960’s era and

is very specialized equipment. Many utilities with hydro units are changing to electronic

governors as it is becoming more difficult to find skilled technicians who can maintain the

older style governors like those installed on the Snare system. Currently NTPC employ a

contractor who retired from the original equipment manufacturer.

Snare Forks units are particularly problematic as there are 2 units operating in parallel

with the same water source and sometimes they will ‘fight’ each other resulting in

instability. Operators will then adjust settings but inevitably wear and/or movement of the

internal components will cause further problems. The result is that many times a year the

system has gone into a ‘hunt’ whereby the slower responding hydro-mechanical

governors do not react fast enough and the system becomes unstable. Usually the

operator can control the swings however if they are unable an outage can result – at the

very minimum customers experience unacceptable power quality. This option of relying

on operator intervention to control swings is not recommended as electronic technology

is now sufficiently advanced that it can quickly react to stabilize these swings.

In addition the distribution system in Yellowknife has been upgraded to 25 kV with more

load per feeder (also less feeders). The greater load on each feeder makes closing the

feeders back after an outage much more difficult as the sudden load can make the

system go unstable. The system was designed for a typical load pickup between 1 – 2

MW and now with the conversion to 25kV the pickup can be up to 3MW or higher

immediately after an outage. This is almost 50% of the capacity of the largest hydro unit

and is not the design parameters of the hydro units. By having the two Snare forks units

and the Snare Falls governors electronic, the operator will be able close feeders quicker

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BR.NTPC-28

June 8, 2012 Page 11 of 20

and with less likelihood of trips during outage restoration as the electronic governors will

work in conjunction to minimize the transient effects. This will result in a smoother

restoration for customers and also should be quicker.

The hydro-mechanical governors on Snare Forks G1 and G2 are low-pressure systems.

This type of governing system is limited to proportional (P) control (very simple feedback

with a slow response). New governors will have proportional-derivative-integral (PID)

control which results in a faster feedback to minimize the potential swings in frequency.

This will give them ability to respond in a quicker and more effective manner to power

system disturbances.

New PLC (Programmable Logic Controller) based unit controllers and HMIs (Human –

Machine Interface) are also required to replace existing relay controls and analog

monitoring. It is becoming increasingly difficult to maintain the old analog equipment and

the replacement is required due to the age of the existing equipment and to provide

modern control and monitoring.

The Snare Falls units existing governor is considered obsolete and requires upgrading to

the same standard as Snare Forks. In addition the pumps used to pressurize the oil for

the control of the Snare Falls units have worked at the low limit of their performance

curves and this has resulted in some operational problems – this project will install more

appropriately sized pumps to provide a smoother pressure control. The blade system

HPU has poorly sized pumps and the tank capacity will not hold the full contents of the

system; this HPU requires replacement.

The Snare Falls unit controller requires replacement similar to the Snare Forks units.

The Scope of Work can be summarized as:

• Replacement of the hydro-mechanical governors with new Digital Governor

Controllers (DGC) with PID Algorithm.

• Replacement of existing unit controls with a new PLC based unit controller and

PC based HMI.

• Replacement of the HPU with two new high pressure pumps, two unloaders,

accumulator banks, storage tank and electrical control.

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June 8, 2012 Page 12 of 20

• Provision of on-site supervision and commissioning.

• Provision of special tools, test equipment and software required for assembly,

commissioning, operations and maintenance.

• Training NTPC staff in maintenance procedures.

• Providing O&M Manuals and As-Built Drawings.

The options for this project consist of either ‘do nothing’ or replace the hydro-mechanical

governors with electronic governors.

The “do nothing” option was not recommended. The Corporation has an obligation to

serve and provide reliable electricity to the customers in the Snare/Yellowknife zone.

The Snare hydro units represent the backbone of the system and the need to ensure the

quality of power from these units is to the highest standard a priority for the Corporation.

It is not acceptable to have equipment controlling key hydro units that is obsolete and

becoming increasingly difficult to maintain, and also cannot respond quickly enough

during system disturbances.

The recommended option was a digital governor upgrade. Digital governors improve the

response time during step load changes and will improve system stability. The

Corporation is going to upgrade the governors at Snare Forks and Snare Falls which will

have the largest improvement.

The budget is shown in Table 2 below.

Table 2:

Digital Governor Upgrade ($000s)

Electronic Governor Supply 1,400 Installation Snare Falls 300 Installation Snare Forks 300 Engineering & Project Management 400 Contingency 400 Overhead & AFUDC 500

3,300

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June 8, 2012 Page 13 of 20

(i)

In Fort Smith some customers are experiencing low voltage issues due to overloading of

the lines. In addition there is the potential to increase electric heat sales using surplus

hydro from the Taltson hydro facility. However, the existing distribution system was not

designed for these increased loads and the Corporation retained the services of an

engineering consulting firm that specializes in power line design and power distribution

planning. The firm examined the existing distribution system and developed a

distribution planning study. The study identified the following items:

1. Existing conditions of the distribution system;

2. Limitations of the existing system;

3. Solutions to improve the distribution system;

4. Future distribution load growth; and

5. Proposed improvements to accommodate future distribution load growth.

The firm examined the existing feeder limits and determined the distribution system

feeder system should be reconfigured for future and current loads. Please refer to Table

3 below showing the existing feeder loading.

Table 3:

Existing Feeder Loading at 4160V

Feeder

Current Peak

Loading (MW)

Current Peak

Loading (MVA)

Current Peak

Loading (A at 4160V)

Remaining Feeder Capacity (Winter Loading)

F1 1.78 2.09 291 3%F2 1.42 1.67 232 23%F3 1.65 1.94 269 10%F4 1.08 1.27 176 41%

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June 8, 2012 Page 14 of 20

System reconfigurations were recommended to increase the feeder capacity on

Feeder 1. This work is forecast to be completed from 2011/12 to 2013/14. The

distribution upgrade is a multi-year project capitalized in 2013/14. The total capital

expenditures by year are shown in Table 4 below.

Table 4:

Distribution Upgrade Expenditures by Year ($000s)

The work completed in 2010/11 included engineering, feasibility and study costs. Work

completed from 2011/12 to 2013/14 includes reducing the load on Feeder 1 by

transferring loads to other feeders. Follow up work after reducing the load on Feeder 1

will include addressing any local voltage issues at the ends of feeders such as by

capacitor bank installations; reduce the number of customers affected from unplanned

outages through the implementation of fuse co-ordination and installation of auto

recloser equipment.

Alternatives included upgrading the entire town to a 25KV voltage which required a new

substation for the increased load. This option was not selected due to capital costs and

the option selected addressed the reliability and capacity issues currently faced by the

community.

(j)

An external consultant conducted a plant assessment for the standby diesel plant in Fort

Smith. When the plant was built in 1972 the engineering life expectancy was 40 years.

Subsequently, life expectancy of power plants has decreased however due to the nature

of the standby plant it was recommended to retain the plant with various upgrades rather

than build a new one. To date, the plant roof has been upgraded to improve insulation

and provide new metal cladding. The overall cost of the upgrades will be less expensive

than building a new standby plant.

2010/11 Actual

2011/12 Forecast

2012/13 Forecast

2013/14 Forecast Total

Expenditure 166 400 313 396 1,274

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June 8, 2012 Page 15 of 20


Forecast Capital Additions 2007/08 ($000s)

Project Name Hydro Thermal Transmission Distribution General Plant EUG Total Snare Zone

Bluefish - Buttress Dam 1,914 1,914 Bluefish - New Intake Structure 1,787 1,787 Bluefish - Duncan Lake Dam 1,742 1,742 Snare Rapids Plant Upgrade 1,305 1,305 Snare 5B Spillway Bridge Refurbishment 460 460 Snare Forks - Static Exciters 300 300 Bluefish - Power Tunnel Rock Repair 147 147 Snare - Warehouse Facility 105 105 Snare Rapids - Refurbish/Automate Fire Pump 60 60 Snare - Road Upgrade 50 50 Snare Control System Digital Upgrade 50 50 Bluefish - Tunnel Bulkhead Assessment/Refurbish 50 50 Install Firehydrants 50 50 Upgrade Rae Feeder from Franks Channel 314 314 Bluefish - Replace Loader 150 150 Replace/Upgrade IT Equipment 101 101 Snare - Crewcab Flatdeck 52 52 Crewcab Pickup 3/4 Ton 52 52 Capital Additions Under $50,000 172 59 216 447

Sub-Total 8,141 109 314 571 9,135

Taltson ZoneTaltson - Retrofit Governor Sump/Filtration System 179 179 Taltson - Replace plant relays with PLC 60 60 Yard Storage Facilities 120 120 Modify Engine Cooling Systems 60 60 Relocate Standby Diesel and Fuel Tank 50 50 Forklift/Loader 60 60 Capital Additions Under $50,000 45 142 187

Sub-Total 239 275 202 716

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Attachment BR.NTPC-28(b) – 1 Con’t

Forecast Capital Additions 2007/08 ($000s)

Project Name Hydro Thermal Transmission Distribution General Plant EU G Total Thermal Communities

Modular Genset Power Plant 5,270 5,270 Replace Cat 3516 800 800 New Office/Garage/Shop 500 500 Repair K-Plant Foundation Piles 450 450 Tank Farm Upgrade 350 350 Upgrade Fuel Oil Storage System 293 293 Upgrade Fuel Oil Storage System 254 254 Replace CAT D342 225 225 Upgrade Plant Exterior 200 200 PLC Installation 159 159 Upgrade Fuel Oil Storage System 147 147 Upgrade K-Plant Ventilation System 145 145 Rebuild Administration Building Parking Area 140 140 Replace Switchgear 140 140 Tank Farm Upgrade 121 121 Replace Feeder Breakers and Cables 120 120 Upgrade Protective Relays 100 100 Reroof K-Plant 100 100 Upgrade Plant Exterior 100 100 Powerhouse Extension 80 80 Switchgear Replacement 61 61 Install Proper Plant Ventilation 61 61 Additional Fuel Strorage Capacity 55 55 Replace DD50 Engine Block 50 50 Three Phase Distribution 60 60 Replace Line/Digger Truck 250 250 New Office Trailer 129 129 Upgrade Office/Transient Quarters 100 100 Replace/Upgrade IT Equipment 60 60 Miscellaneous Small Capital 50 50 Capital Additions Under $50,000 95 40 86 221

Sub-Total 10,018 100 674 10,793

Corporate/Head OfficeStrategic Plan Alignment Projects 50 50 100 System Control & Supervisory Systems 300 300 Emergency Genset 300 300 Fire Suppression Upgrade 150 150 Noise Suppression Measures 125 125 Fire Detection Upgrade 125 125 In-Plant Fuel System Upgrades 100 100 Automatic Meter Reading (Turtle) 200 200 Distribution Upgrades 150 150 Streetlight Upgrades 100 100 Distribution Extension - Non Recoverable Type 5 93 93 Distribution Extension - Non Recoverable Type 6 52 52 Safety/Legislative Upgrades 250 250 Replace/Upgrade IT Equipment 178 178 Plant Communications/Automation Upgrades 100 100 Relay Test Equipment 50 50 Vehicle Replacements 50 50 Capital Additions Under $50,000 64 60 124

Sub-Total 50 1,150 659 688 2,547

Total 8,430 11,552 1,072 2,135 23,190

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June 8, 2012 Page 17 of 20


Actual Capital Additions 2007/08 ($000s)

Project Name Hydro Thermal Transmission Distribution General

Plant EUG Total Snare Zone

Bluefish - New Intake Structure 2,029 83 2,112Bluefish - Duncan Lake Dam 1,837 1,837Snare 5B Spillway Bridge Abutment Replacement 844 844Snare Rapids Plant Upgrade 484 93 577Plant Communication/Automation Upgrades 292 292Bluefish Power Tunnel Rock Repair 233 233Duncan Lake Helipad and Walkways 163 163Walkways to Intake Valves 92 92Vibration Data Sensors 68 68Buttress Bluefish Dam 51 51Emergency Detroit Diesel 407 407EMD Fuel System 268 268Upgrade Roof for K-Plant 128 128Jackfish Water Safety 55 55Survalent SCADA Software-Jackfish System 394 394Distribution Extension to Highway Junction 120 120Bluefish-14 Person Camp. 212 212Replace Loader 143 143Replace PLC w/ Fibre at Snare 120 120Replace/Upgrade IT Equipment 110 110Upgrade ScadaCom Software 98 98Upgrade ScadaCom Servers 90 90Implement IEC60870 Protocol 82 82Replace Snare Tie Sub PLC 69 69Replace Jackfish PLC 64 64Capital Additions Less Than $50,000 6 61 169 235

Sub-Total 6,093 865 394 181 1,333 8,865

Taltson ZoneNew Standby Powerplant 1,348 1,348Upgrade Fuel System 265 265Straighten Tower 24Km outside 140 140Automatic Meter Reading 129 129Replacement Truck 62 62Optical Isolation Phone Lines 54 54Capital Additions Less Than $50,000 35 17 136 188

Sub-Total 35 1,613 140 146 252 2,185

Thermal CommunitiesModular Genset Power Plant 7,041 7,041Emergency Detroit Diesel Series 60 415 415Upgrade Fuel Oil System 222 222Upgrade Interior Fuel System 167 167Tank Farm Upgrade 77 77Engine Swap Tier 3 for Tier 2 77 77Water Treatment System 109 109Replace Truck - Digger Derrick 206 206Repalce Bucket Truck 163 163Optical Isolation Phone Lines 54 54Replace/Upgrade IT Equipment 50 50Capital Additions Less Than $50,000 82 95 235 412

Sub-Total 8,081 204 707 8,991

Corporate/Head OfficeNew Computer System 1,568 1,568Replace/Upgrade IT Equipment 240 240NTPC Safety Orientation Video filmed 123 123Trailers for Emergency Gensets (2) 70 70Capital Additions Less Than $50,000 377 377

Sub-Total 2,378 2,378

Total 6,128 10,558 533 530 4,669 22,419

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June 8, 2012 Page 18 of 20



Project Name Hydro Thermal Transmission Distrib ution General Plant EUG Total Snare Zone

Bluefish Dam New Intake Structure 2,806 2,806Snare 5B Spillway Bridge North Abutment 939 939Transformer Replacement 682 682Install Static Exciter G1 - Snare Forks 325 325Bluefish Emergency Spillway 2008/09 296 296

Uprade Step-up Transformers 196 1968 Person Wet Sleeper - Snare Hydro 162 162Bluefish Tunnel Ventilation System 105 105Insulate Penstock Butterfy Valves 81 81Security Fencing - Grounding 76 76Purchase Oil/Water Skimmers - Bluefish 67 67New Roof K-Plant G1 Engine Bay 129 129Concrete Pad & Berm around FCT1 & FCT2 67 67Concrete Pad & Berm - Jackfish 64 6425 KV Oile Circuit Recloser & Airbrakes 53 53Replace/Upgrade IT Equipment 147 147Purchase Dump Truck - White 128 128Bobcat Utility Service Vehicle 72 72Purchase Work Boat 71 71Crew Cab - Snare 50 50Crew Cab - Snare 50 50Capital Additions Less Than $50,000 116 8 17 179 321

Sub-Total 5,851 137 184 17 697 6,886

Taltson ZoneRetrofit Governor Sump & Filtration 540 540Replace Fort Smith PLC 127 127Upgrade Plant Ventilation 104 104Replace Plant Relays w/ PLC 99 99

Replace Taltson PLC 89 89Install Fort Smith PLC 66 663-Phase Line from Pine Point 1,599 1,599Install Turtle Meters 79 79Capital Additions Less Than $50,000 54 35 111 52 252

Sub-Total 1,079 1,634 190 52 2,955

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June 8, 2012 Page 19 of 20

Attachment BR.NTPC-28(b) – 3 Con’t


Project Name Hydro Thermal Transmission Distrib ution General Plant EUG Total Snare ZoneThermal Communities

Repair K-Plant Foundation Piles 882 882New Office and Garage 508 168 676New Office/Transient Trailer 340 340Install PLC 287 287Aklavik Power Plant Upgrades 283 283Genset Replacement 270 270New Office/Transient Trailer 253 253Tank "C" Bulk Fuel Tank Repairs & Upgrades 243 243Ft. McPherson Building Improvements 216 216Upgrade Fuel Oil Storage System 193 193Upgrade Plant Fuel System 184 184Replace/Repair Switchgear 184 184Improvements to Nalluk Base Tank Farm. 130 130Inuvik Glycol Distillation System 91 91Curtain-Side Transient Trailers x2 86 86Install Security Fence Grounding 83 83Repair Power Plant Roof 78 78Purchase 3x500 kW Load Bank 72 72Coolant System- Fort McPherson New Power 67 67Install Security Fence Grounding 50 50Install Turtle Meters 192 192Purchase Revenue Meters 76 76New Building Envelope assembly K-Plant 772 772Replace Bucket Truck 173 173Replace Front End Loader 140 140Replace/Upgrade IT Equipment 85 85Replace Crew Vehicle 76 76Refurbish Corporate Accomodations 66 66Upgrade Staff House 65 65Insurance Proceeds (Inuvik) -162 -162Capital Additions Less Than $50,000 28 481 944 1,454

Sub-Total 4,529 749 2,327 7,605

Corporate/Head Office2 MVA Skid Mounted Transformer for EM5 70 70Replace/Upgrade IT Equipment 200 200Warehouse Water & Sewer Replacement 120 120New Roof Assembly Head Office Warehouse 117 117Head Office Carpets 89 89New Meter Shop Structure,Electrical & 63 63Replace Flat Deck Truck 51 51Capital Inventory -681 -681Capital Additions Less Than $50,000 75 75

Sub-Total 70 34 104

Total 6,930 4,736 1,819 956 3,110 17,551

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June 8, 2012 Page 20 of 20



Project Name Hydro Thermal Transmission Distrib ution General Plant EUG Total Snare Zone

Transformer Replacement 5,019 5,019Snare Rapids Side Dam Repairs 449 449Bluefish Dam New Intake Structure 225 225Upgrade Vehicle Bulk Fuel Storage Tank 217 217Cold Storage Facility - Bluefish 216 216Cold Storage Facility 131 131Main Dam Repairs 110 110Bluefish Security Alarms & Cameras 96 96Replace RipRap - Snare Forks 68 68Vibration Data Collection & Software 63 63Resurface Access Roads - Snare 62 62Fuel Tank Berm Upgrade - Jackfish 914 914EMD Roof Upgrade 188 188Glycol Distilation System 92 92Substation Transformer Secondary Containment 364 364Upgrade Franks Channel Feeder 460 460Streelighting 123 123Relocate Edzo Feeder to Highway 111 111Purchase OCR & Ancilliary Equipment 47 47Purchase Mixer Truck 252 252Replace/Upgrade IT Equipment 195 195Replace Grader 183 183Snare Staff House improvements 137 137Purchase Dump Truck 121 121Replace Radio Repeater - Snare 100 100New Vehicle 64 64Purchase Bruch Cutter 60 60Capital Additions Less Than $50,000 68 67 98 233

Sub-Total 6,723 1,194 364 809 1,211 10,302

Taltson ZoneAccess Ventilation Fans & Crane 226 226Install Pine Point Power Line Carrier 109 109Upgrade Plant Ventilation 81 81Fort Resolution Standby Plant 162 162Assessment & Planning Study Report 79 79Upgrade Engine Block & Plant Space Heater 60 60Brenant Hall & Elementary School 127 127Widen Power Line Right of Way 92 92Ft Smith Catholic Chruch Electric Boiler 56 56Capital Additions Less Than $50,000 42 55 74 170

Sub-Total 458 302 329 74 1,163

Thermal CommunitiesUpgrade Fuel Storage System 502 502EMD Plant Roof Upgrade 371 371Upgrade In-Plant Fuel Systems 341 341Replace 12V4000 MTU 338 338K-Plant Foundation Upgrade 219 219Roof Replacement 108 108New Power Plant Door 89 89Ground Fence around Plant Property 71 71Replace CAT D399 60 60Concrete Apron for Plant 54 54Distribution Extensions 80 80Distribution Extensions 70 70Streetlight Conversion 60 60Replace Warehouse Truck 69 69Replace/Upgrade IT Equipment 70 70Capital Additions Less Than $50,000 212 308 276 796

Sub-Total 2,365 518 414 3,297

Corporate/Head OfficeReplace/Upgrade IT Equipment - Hay River 187 187Major Spare Parts 3,728 3,728Capital Additions Less Than $50,000 52 52

Sub-Total 3,967 3,967

Total 7,182 3,861 364 1,656 5,667 18,729

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BR.NTPC-29


TOPIC:

Service Quality

PREAMBLE:

The Board wishes to assess NTPC's service quality measures.

REQUEST:

a) Please provide NTPC's service quality metrics for reliability, safety, customer

service, billing and meter reading for each of 2010/11 and 2011/12.

b) Please provide a comparison of NTPC's service quality metrics with those of

NTPC's peers and comment on any material differences.

RESPONSE:

(a) and (b)

Safety The Corporation measures safety statistics by calendar year and compares them against

other CEA utilities with similar size and function. As a fully integrated utility (i.e.,

generation, transmission, and distribution) with less than 200 employees it is difficult to

find a suitable comparison utility. Comparisons utilities in the Table 1 below are the

closest in size and function. Data for 2009 and 2010 are presented below as utility

information for 2011 is not yet available.

To explain differences in statistics from other utilities for a small company with relatively

low exposure hours, one or two lost time accidents can have a significant effect on the

Accident Severity Rate.

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Table 1:

Safety Metrics

Notes:

• Exposure hours include all hours worked, but exclude leave, lost time, and training hours. • Accident Severity Rate is measured as the number of lost time days per 200,000 exposure hours. • The 5 Year Rolling Average is simply the average Accident Severity Rate over the past five years. • Lost time accidents have greater statistical impacts on smaller companies such as NTPC with fewer employees.

Exposure Hours N/A 380,292 165,649 80,782 853,602 1,252,353 743,279 N/A 147,462 318,733Lost Time Days N/A 19 7 0 100 76 28 N/A 0 17.5Annual Accident Severity Rate N/A 9.99 8.45 0 23.43 12.14 7.53 N/A 0 10.985 Year Rolling Average Accident Severity 44.01 13.11 23.86 0 12.09 3.86 4.22 0.13 3.71 12.07Exposure Hours N/A 365,822 171,795 N/A 928,150 1,270,202 802,235 102,420 148,968 330,098Lost Time Days N/A 3 32 N/A 27 45 0 0 0 7Annual Accident Severity Rate N/A 1.64 37.25 N/A 5.82 7.09 0 0 0 4.245 Year Rolling Average Accident Severity 57.04 13.11 30.4 0 13.07 4.99 3.62 0 2.86 12.92

Brookfield Renewable

Great Lakes

Yukon Energy

NTPC

2009

2010

Hydro Sherbrooke

Maritime Electric

Medicine Hat

Electric

Orillia Power

Fortis BCHydro Ottawa

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Billing & Meter Reading

The Corporation maintains an internal monthly billing control report. The report is used

by the billing department to maintain a billing schedule in accordance with the Board

approved Terms & Conditions of service. The Corporation uses the control report as a

tool to maintain a 30 day billing cycle. Meter reads, billing input cycles are adjusted for

weekends, statutory holidays and other planned events to manage to a 30 day billing

period. The Corporation does not have a peer group comparison.

For billing quality the Corporation maintains an internal report on the number of

estimated bills and held bills for quality control purposes. In accordance with Board

approved Terms & Conditions of Service the Corporation may use meter read estimates

however the Corporation strives to minimize the number of estimates. The Corporation

will also hold bills for a short period of time if the monthly consumption significantly

differs from previous months or patterns. The Corporation investigates and will conduct

re-reads and may contact the customer to ensure the measured consumption is

accurate.

Table 2 below shows the monthly billing cycle for all customers served by the

Corporation. It also shows the estimated bill ratio and the held bill ratio as a percentage

of total monthly bills.

Table 2:

Monthly Billing Cycle and Bill Quality Control

Estimated bill ratio = estimated bills / total customers

Held bill ratio = held bills / total customers

Fiscal year

Average Bill Cycle

Estimated Bill Ratio

Held Bill Ratio

2009/10 30.44 0.79% 0.79%2010/11 30.41 0.28% 1.11%2011/12 30.53 0.12% 0.87%

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Customer Service

Historically NTPC conducts an annual survey to measure customer service statistics and

compares them against other CEA utilities. Table 3 below shows the percentage of

residential customers who rated utilities with a “good” or “satisfactory” rating level.

Table 3:

Total Customer Satisfaction

Table 4 below shows key aspects of the 2011 residential customer satisfaction survey.

Table 4:

Key Aspects of 2011 Survey

Reliability

NTPC calculates customer service continuity indicators defined by the Canadian

Electricity Association (CEA) as a method of monitoring reliability. These indicators

include the System Average Duration Index (SAIDI), System Average Interruption

Frequency Index (SAIFI), and Customer Average Interruption Duration Index (CAIDI).

The CEA defines SAIDI, SAIFI, and CAIDI as follows:

• SAIDI: System average interruption duration for customers served per year.

(Hours without service).

• CAIDI: Average duration of interruption, for customers who have experienced

interruptions during the year. (Restoration time).

• SAIFI: Average number of interruptions per customer served per year (Number of

outages).

2007 2008 2009 2010 2011CEA Utilities 79% 80% 65% 64% 59%NTPC 85% 83% 84% 80% 85%

Price of Electricity Reliability Restoration

Courteous Staff Communications

Concern for Public Safety

Environmentally Responsible

Encourages Energy

EfficiencyCEA Utilities 55% 76% 75% 74% 72% 76% 72% 75%

NTPC 62% 63% 58% 74% 85% 86% 69% 81%

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Northwest Territories utility customers typically experience more frequent service

interruptions of significantly shorter duration than consumers in other regions of Canada.

This is a result of the isolated-grid infrastructure in the north. Disturbances in the

generation supply on this type of system will normally result in customer disruptions.

The typically short duration of NTPC’s service interruptions offsets their higher

frequency, resulting in overall system availability comparable to, or better than, the

Canadian average in most years.

Reliability Indicators for the 2009 through 2011 calendar years are presented in Table 5.

NTPC is included in the CEA Region 2 (Urban/Rural Utilities Group). This group

provides the best available national-level comparison for NTPC’s statistics, however it

does include many utilities which primarily operate as part of the North American Grid,

such as Nova Scotia Power, Fortis, Alberta, and B.C. Hydro.

Table 5:

Service Continuity Indicators by Calendar Year

NTPC CEA

(Urban/Rural)

CEA (All

Utilities)

2009 SAIDI 2.47 5.31 4.20

SAIFI 7.07 2.31 2.01

CAIDI 0.35 2.30 2.09

2010 SAIDI 7.72 7.06 5.17

SAIFI 12.65 2.55 2.20

CAIDI 0.61 2.35 1.83

2011 SAIDI 2.57 7.53 6.16

SAIFI 7.11 2.98 2.63

CAIDI 0.36 2.53 2.34

nwt public utilities board (br)

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