NWT Public Utilities Board
(BR)
Information Request
NTPC GRA 2012/13 and 2013/14
NWT Public Utilities Board
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
NWT Public Utilities Board
BR.NTPC-1
June 8, 2012 Page 2 of 2
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
NWT Public Utilities Board
BR.NTPC-3
June 8, 2012 Page 1 of 2
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
NWT Public Utilities Board
BR.NTPC-3
June 8, 2012 Page 2 of 2
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
NWT Public Utilities Board
BR.NTPC-4
June 8, 2012 Page 1 of 5
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
significant variances from year to year.
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
significant variances from year to year.
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
NWT Public Utilities Board
BR.NTPC-4
June 8, 2012 Page 2 of 5
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
NWT Public Utilities Board
BR.NTPC-4
June 8, 2012 Page 3 of 5
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
NWT Public Utilities Board
BR.NTPC-4
June 8, 2012 Page 4 of 5
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
NWT Public Utilities Board
BR.NTPC-4
June 8, 2012 Page 5 of 5
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
NWT Public Utilities Board
BR.NTPC-5
June 8, 2012 Page 1 of 4
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.
Information Request
NTPC GRA 2012/13 and 2013/14
NWT Public Utilities Board
BR.NTPC-5
June 8, 2012 Page 2 of 4
• 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
NWT Public Utilities Board
BR.NTPC-5
June 8, 2012 Page 3 of 4
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
NWT Public Utilities Board
BR.NTPC-5
June 8, 2012 Page 4 of 4
Attachment BR.NTPC-5(a)
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
Variance to 2007/08 Actual
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
NWT Public Utilities Board
BR.NTPC-6
June 8, 2012 Page 1 of 3
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.
Information Request
NTPC GRA 2012/13 and 2013/14
NWT Public Utilities Board
BR.NTPC-6
June 8, 2012 Page 2 of 3
• 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
NWT Public Utilities Board
BR.NTPC-6
June 8, 2012 Page 3 of 3
Attachment BR.NTPC-6(a)
Travel and Accommodations Expenses by Prime Account ($000s)
Description
2007/08 Total
Forecast
Variance to 2007/08 Actual
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
NWT Public Utilities Board
BR.NTPC-7
June 8, 2012 Page 1 of 10
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
NWT Public Utilities Board
BR.NTPC-7
June 8, 2012 Page 2 of 10
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
NWT Public Utilities Board
BR.NTPC-7
June 8, 2012 Page 3 of 10
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
NWT Public Utilities Board
BR.NTPC-7
June 8, 2012 Page 4 of 10
(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
NWT Public Utilities Board
BR.NTPC-7
June 8, 2012 Page 5 of 10
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
NWT Public Utilities Board
BR.NTPC-7
June 8, 2012 Page 6 of 10
Attachment BR.NTPC-7(b) – 2
2009/10 Actual Long-Term Debt Continuity Schedule ( $000s)
Line Loan Number 1 2 3 4 5 6 7 8No. Loan Amount 15,000$ 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
NWT Public Utilities Board
BR.NTPC-7
June 8, 2012 Page 7 of 10
Attachment BR.NTPC-7(b) – 3
2010/11 Actual 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 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
NWT Public Utilities Board
BR.NTPC-7
June 8, 2012 Page 8 of 10
Attachment BR.NTPC-7(b) – 4
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
7 Mid-Year Debt Balance (MAD) [(L3+L6)/2] 7,500 20,000 8,700 10,000 14,333 25,000 15,000 25,000 50,000 175,533
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
17 Average Financing Costs (UFC) [(L13+L16)/2] 1 2 25 38 7 91 144 78 123 240 1,441
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
NWT Public Utilities Board
BR.NTPC-7
June 8, 2012 Page 9 of 10
Attachment BR.NTPC-7(b) – 5
2012/13 Forecast Long-Term Debt Continuity Schedule ($000s)
Line Loan Number 1 2 3 4 5 6 7 8 9No. Loan Amount 20,000$ 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
7 Mid-Year Debt Balance (MAD) [(L3+L6)/2] 10,000 8,700 10,000 13,666 25,000 15,000 25,000 49,601 12,500 169,467
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
17 Average Financing Costs (UFC) [(L13+L16)/2] 0 24 33 72 5 138 72 116 231 74 1,413
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
NWT Public Utilities Board
BR.NTPC-7
June 8, 2012 Page 10 of 10
Attachment BR.NTPC-7(b) – 6
2013/14 Forecast Long-Term Debt Continuity Schedule ($000s)
Line Loan Number 1 2 3 4 5 6 7 8No. Loan Amount 8,700$ 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
NWT Public Utilities Board
BR.NTPC-8
June 8, 2012 Page 1 of 3
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
NWT Public Utilities Board
BR.NTPC-8
June 8, 2012 Page 2 of 3
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
NWT Public Utilities Board
BR.NTPC-8
June 8, 2012 Page 3 of 3
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
NWT Public Utilities Board
BR.NTPC-9
June 8, 2012 Page 1 of 3
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
NWT Public Utilities Board
BR.NTPC-9
June 8, 2012 Page 2 of 3
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
NWT Public Utilities Board
BR.NTPC-9
June 8, 2012 Page 3 of 3
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
NWT Public Utilities Board
BR.NTPC-10
June 8, 2012 Page 1 of 8
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
NWT Public Utilities Board
BR.NTPC-10
June 8, 2012 Page 2 of 8
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
NWT Public Utilities Board
BR.NTPC-10
June 8, 2012 Page 3 of 8
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
NWT Public Utilities Board
BR.NTPC-10
June 8, 2012 Page 4 of 8
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
NWT Public Utilities Board
BR.NTPC-10
June 8, 2012 Page 5 of 8
Attachment BR.NTPC-10(a)
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 ($000)27 Opening Deficiency (Surplus) 10,123 10,019 9,702 9,520 10,252 10,408 10,104 9,814 9,706 9,665 2,996 3,37328 Refund/ (Collection) Rider (117) (373) (373) (291) (328) (350) (358) (375) (248) (34) (1) (4)29 Snare Cascades Transfer (85)30 Shortfall Rider Applied to Stab Fund (3,901)31 Rider Payment by GNWT (3,000)32 Additional (Less) Diesel Cost (L11) (1) 41 175 1,004 464 25 48 246 202 314 372 30733 Fuel storage cost 0 0 0 0 1 1 0 0 (15) 30 0 034 Closing Balance Before Interest 10,005 9,688 9,504 10,233 10,388 10,083 9,794 9,686 9,645 2,989 3,366 3,67735 Interest Charged (Earned) 15 14 16 19 19 21 20 20 20 6 7 8
36 Closing Deficiency (Surplus) 10,019 9,702 9,520 10,252 10,408 10,104 9,814 9,706 9,665 2,996 3,373 3,685
Actual
Information Request
NTPC GRA 2012/13 and 2013/14
NWT Public Utilities Board
BR.NTPC-10
June 8, 2012 Page 6 of 8
Attachment BR.NTPC-10(a) Con’t
NORTHWEST TERRITORIES POWER CORPORATION
TERRITORY-WIDE FUEL AND WATER STABILIZATION FUND
CONTINUITY SCHEDULE - 2011/12 ACTUAL
Notes:
1. The calculations are based on actual diesel and gas generation for the entire period.
2. The efficiency rates used are those approved by the Public Utilities Board in the most recent GRA.
3. The interest rate used is equal to the Prime Rate in effect at the Corporation's bank at the last actual month end, less 50 basis points, applied to the month end balance in the
funds.
Line 2011 2011 2011 2011 2011 2011 2011 2011 2011 2012 2012 2012no. Explanation April May June July August September October No vember December January February March
1 Diesel generation (MWh) 4,564 4,260 4,087 3,691 4,228 3,380 3,836 4,287 4,177 5,554 6,581 6,6592 Corporate approved plant efficiency (kWh/L) 3.596 3.589 3.598 3.561 3.528 3.580 3.586 3.581 3.583 3.591 3.604 3.604
3=1/2 Litre of Fuel Required (000) 1,269 1,187 1,136 1,037 1,198 944 1,070 1,197 1,166 1,546 1,826 1,8484 Approved fuel price w.a. ($/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. ($/L) 1.010 1.040 1.032 1.055 1.073 1.127 1.133 1.150 1.153 1.155 1.147 1.157
6=5-4 Fuel price variance from approved ($/L) 0.105 0.132 0.130 0.154 0.172 0.196 0.200 0.222 0.211 0.241 0.265 0.2727=3*6 Fuel cost from diesel generation ($000) 134 157 148 160 206 185 214 265 246 372 483 502
8 Gas generation (MWh) 1,238 1,517 1,239 2,327 2,195 2,305 2,395 2,664 2,902 1,924 121 342
9 Corporate approved plant efficiency (kWh/m3) 3.399 3.399 3.399 3.399 3.399 3.399 3.399 3.399 3.399 3.399 3.399 3.39910=8/9 Gas Fuel Required (m3) (000) 364 446 365 685 646 678 705 784 854 566 36 101
11 Approved gas price ($/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
25=23*24 Fuel cost due to water level ($000) 2 23 17 122 54 49 29 51 22 10 0 4
26 Additional (Less) Diesel / Gas Cost ($000) 295 282 292 283 3 32 295 351 426 410 591 830 823
Consolidated Fund Continuity ($000)27 Opening Deficiency (Surplus) 3,685 3,988 1,275 1,570 1,857 2,194 1,492 1,847 2,278 2,693 2,189 3,02528 Refund/ (Collection) Rider 0 0 () 0 0 () 0 0 0 0 0 029 Rider Payment by GNWT 0 (3,000) 0 0 0 (1,000) 0 0 0 (1,100) 0 030 Additional (Less) Diesel Cost (L11) 295 282 292 283 332 295 351 426 410 591 830 82331 Fuel storage cost 0 3 0 0 0 0 0 0 0 0 0 032 Closing Balance Before Interest 3,980 1,272 1,567 1,853 2,190 1,489 1,843 2,273 2,688 2,184 3,019 3,84833 Interest Charged (Earned) 8 3 3 4 5 3 4 5 6 5 6 83435 Closing Deficiency (Surplus) 3,988 1,275 1,570 1,857 2,194 1,492 1,847 2,278 2,693 2,189 3,025 3,856
Actual
Information Request
NTPC GRA 2012/13 and 2013/14
NWT Public Utilities Board
BR.NTPC-10
June 8, 2012 Page 7 of 8
Attachment BR.NTPC-10(a) Con’t
NORTHWEST TERRITORIES POWER CORPORATION
TERRITORY-WIDE FUEL AND WATER STABILIZATION FUND
CONTINUITY SCHEDULE – 2012/13 FORECAST
Notes:
1. The calculations are based on forecast diesel and gas generation for the entire period.
2. The efficiency rates used are those proposed in 2012/14 GRA.
3. The interest rate used is equal to the Prime Rate in effect at the Corporation's bank at the last actual month end, less 50 basis points, applied to the month end balance in the
funds.
Line 2012 2012 2012 2012 2012 2012 2012 2012 2012 2013 2013 2013no. Explanation April May June July August September Octobe r November December January February March
1 Diesel generation (MWh) 6,336 5,913 5,674 5,124 5,869 4,693 5,325 5,951 5,799 7,710 9,136 9,2442 Corporate proposed plant efficiency (kWh/L) 3.532 3.532 3.532 3.532 3.532 3.532 3.532 3.532 3.532 3.532 3.532 3.532
3=1/2 Litre of Fuel Required (000) 1,794 1,674 1,606 1,451 1,662 1,329 1,508 1,685 1,642 2,183 2,587 2,6174 Proposed fuel price w.a. ($/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. ($/L) 1.129 1.129 1.129 1.129 1.129 1.129 1.129 1.129 1.129 1.129 1.129 1.129
6=5-4 Fuel price variance from approved ($/L) 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.0007=3*6 Fuel cost from diesel generation ($000) 0 0 0 0 0 0 0 0 0 0 0 0
8 Gas generation (MWh) 0 0 0 0 0 0 0 0 0 0 0 09 Corporate approved plant efficiency (kWh/m3) 3.350 3.350 3.350 3.350 3.350 3.350 3.350 3.350 3.350 3.350 3.350 3.350
10=8/9 Gas Fuel Required (m3) (000) 0 0 0 0 0 0 0 0 0 0 0 011 Proposed gas price ($/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
15 Fuel cost due to difference in 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 ($/kWh) 0.357 0.357 0.357 0.357 0.357 0.357 0.357 0.357 0.357 0.357 0.357 0.357
19=18-17 Purchased power price variance ($/kWh) 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.00020=16*19 Fuel cost from purchased power ($000) 0 0 0 0 0 0 0 0 0 0 0 0
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
26=24*25 Fuel cost due to water level ($000) 0 0 0 0 0 0 0 0 0 0 0 0
27 Diesel generation above 0.96 GWh due to water level (MWh) 0 0 0 0 0 0 0 0 0 0 0 028 Proposed plant efficiency (kWh/L) 3.432 3.432 3.432 3.432 3.432 3.432 3.432 3.432 3.432 3.432 3.432 3.432
29=27/28 Litre of Fuel Required (000) 0 0 0 0 0 0 0 0 0 0 0 030 Taltson zone proposed GRA fuel price ($/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
31=29*30 Fuel cost due to water level ($000) 0 0 0 0 0 0 0 0 0 0 0 0
32 Additional (Less) Diesel / Gas Cost ($000) 0 0 0 0 0 0 0 0 0 0 0 0
Consolidated Fund Continuity ($000)33 Opening Deficiency (Surplus) 3,856 0 0 0 0 0 0 0 0 0 0 034 Refund/ (Collection) Rider35 Rider Payment by GNWT (3,856)36 Additional (Less) Diesel Cost (L11) 0 0 0 0 0 0 0 0 0 0 0 037 Fuel storage cost38 Closing Balance Before Interest 0 0 0 0 0 0 0 0 0 0 0 039 Interest Charged (Earned) 0 0 0 0 0 0 0 0 0 0 0 0
40 Closing Deficiency (Surplus) 0 0 0 0 0 0 0 0 0 0 0 0
Forecast
Information Request
NTPC GRA 2012/13 and 2013/14
NWT Public Utilities Board
BR.NTPC-10
June 8, 2012 Page 8 of 8
Attachment BR.NTPC-10(a) Con’t
NORTHWEST TERRITORIES POWER CORPORATION
TERRITORY-WIDE FUEL AND WATER STABILIZATION FUND
CONTINUITY SCHEDULE – 2013/14 FORECAST
Notes:
1. The calculations are based on forecast diesel and gas generation for the entire period.
2. The efficiency rates used are those proposed in 2012/14 GRA.
3. The interest rate used is equal to the Prime Rate in effect at the Corporation's bank at the last actual month end, less 50 basis points, applied to the month end balance in the
funds.
Line 2013 2013 2013 2013 2013 2013 2013 2013 2013 2014 2014 2014no. Explanation April May June July August September Octobe r November December January February March
1 Diesel generation (MWh) 6,452 6,021 5,778 5,218 5,976 4,778 5,423 6,060 5,905 7,851 9,303 9,4132 Corporate proposed plant efficiency (kWh/L) 3.543 3.543 3.543 3.543 3.543 3.543 3.543 3.543 3.543 3.543 3.543 3.543
3=1/2 Litre of Fuel Required (000) 1,821 1,699 1,631 1,473 1,687 1,349 1,530 1,710 1,667 2,216 2,626 2,6574 Proposed fuel price w.a. ($/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. ($/L) 1.129 1.129 1.129 1.129 1.129 1.129 1.129 1.129 1.129 1.129 1.129 1.129
6=5-4 Fuel price variance from approved ($/L) 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.0007=3*6 Fuel cost from diesel generation ($000) 0 0 0 0 0 0 0 0 0 0 0 0
8 Gas generation (MWh) 0 0 0 0 0 0 0 0 0 0 0 0
9 Corporate approved plant efficiency (kWh/m3) 3.356 3.356 3.356 3.356 3.356 3.356 3.356 3.356 3.356 3.356 3.356 3.356
10=8/9 Gas Fuel Required (m3) (000) 0 0 0 0 0 0 0 0 0 0 0 011 Proposed gas price ($/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
15 Fuel cost due to difference in 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 ($/kWh) 0.357 0.357 0.357 0.357 0.357 0.357 0.357 0.357 0.357 0.357 0.357 0.357
19=18-17 Purchased power price variance ($/kWh) 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.00020=16*19 Fuel cost from purchased power ($000) 0 0 0 0 0 0 0 0 0 0 0 0
21 Fuel cost due to difference in PP generation ($000) 0 0 0 0 0 0 0 0 0 0 0 0
22 Diesel generation above 1.2 GWh due to water level (MWh) 0 0 0 0 0 0 0 0 0 0 0 023 Proposed plant efficiency (kWh/L) 3.650 3.650 3.650 3.650 3.650 3.650 3.650 3.650 3.650 3.650 3.650 3.650
24=22/23 Litre of Fuel Required (000) 0 0 0 0 0 0 0 0 0 0 0 025 Snare zone proposed GRA fuel price ($/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
26=24*25 Fuel cost due to water level ($000) 0 0 0 0 0 0 0 0 0 0 0 0
27 Diesel generation above 0.96 GWh due to water level (MWh) 0 0 0 0 0 0 0 0 0 0 0 028 Proposed plant efficiency (kWh/L) 3.458 3.458 3.458 3.458 3.458 3.458 3.458 3.458 3.458 3.458 3.458 3.458
29=27/28 Litre of Fuel Required (000) 0 0 0 0 0 0 0 0 0 0 0 030 Taltson zone proposed GRA fuel price ($/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
31=29*30 Fuel cost due to water level ($000) 0 0 0 0 0 0 0 0 0 0 0 0
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
NWT Public Utilities Board
BR.NTPC-11
June 8, 2012 Page 1 of 10
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
NWT Public Utilities Board
BR.NTPC-11
June 8, 2012 Page 2 of 10
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
NWT Public Utilities Board
BR.NTPC-11
June 8, 2012 Page 3 of 10
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
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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
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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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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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(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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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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(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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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)
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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?
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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
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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
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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.
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NWT Public Utilities Board
BR.NTPC-12
June 8, 2012 Page 5 of 5
Attachment BR.NTPC-12(a)
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)
June 8, 2012 Page 1 of 1
Information Request
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NWT Public Utilities Board
BR.NTPC-13
June 8, 2012 Page 1 of 5
TOPIC:
Depreciation
REFERENCE:
Appendix A, Account 343
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.
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RESPONSE:
(a)
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 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
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NTPC GRA 2012/13 and 2013/14
NWT Public Utilities Board
BR.NTPC-13
June 8, 2012 Page 3 of 5
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.
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NWT Public Utilities Board
BR.NTPC-13
June 8, 2012 Page 4 of 5
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)
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NWT Public Utilities Board
BR.NTPC-13
June 8, 2012 Page 5 of 5
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
NWT Public Utilities Board
BR.NTPC-14
June 8, 2012 Page 1 of 3
TOPIC:
Depreciation
REFERENCE:
Appendix A, Account 345
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
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NWT Public Utilities Board
BR.NTPC-14
June 8, 2012 Page 2 of 3
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.
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 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.
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NWT Public Utilities Board
BR.NTPC-14
June 8, 2012 Page 3 of 3
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
NWT Public Utilities Board
BR.NTPC-15
June 8, 2012 Page 1 of 3
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
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NWT Public Utilities Board
BR.NTPC-15
June 8, 2012 Page 2 of 3
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.
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NWT Public Utilities Board
BR.NTPC-15
June 8, 2012 Page 3 of 3
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
NWT Public Utilities Board
BR.NTPC-16
June 8, 2012 Page 1 of 3
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.
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NWT Public Utilities Board
BR.NTPC-16
June 8, 2012 Page 2 of 3
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
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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
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NWT Public Utilities Board
BR.NTPC-17
June 8, 2012 Page 1 of 2
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.
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NWT Public Utilities Board
BR.NTPC-17
June 8, 2012 Page 2 of 2
(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
NWT Public Utilities Board
BR.NTPC-18
June 8, 2012 Page 1 of 3
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.
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NWT Public Utilities Board
BR.NTPC-18
June 8, 2012 Page 2 of 3
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
NWT Public Utilities Board
BR.NTPC-18
June 8, 2012 Page 3 of 3
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
NWT Public Utilities Board
BR.NTPC-19
June 8, 2012 Page 1 of 3
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
NWT Public Utilities Board
BR.NTPC-19
June 8, 2012 Page 2 of 3
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
NWT Public Utilities Board
BR.NTPC-19
June 8, 2012 Page 3 of 3
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
NWT Public Utilities Board
BR.NTPC-20
June 8, 2012 Page 1 of 2
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
NWT Public Utilities Board
BR.NTPC-20
June 8, 2012 Page 2 of 2
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
NWT Public Utilities Board
BR.NTPC-21
June 8, 2012 Page 1 of 3
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
NWT Public Utilities Board
BR.NTPC-21
June 8, 2012 Page 2 of 3
• 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
NWT Public Utilities Board
BR.NTPC-21
June 8, 2012 Page 3 of 3
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
NWT Public Utilities Board
BR.NTPC-22
June 8, 2012 Page 1 of 10
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
NWT Public Utilities Board
BR.NTPC-22
June 8, 2012 Page 2 of 10
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
NWT Public Utilities Board
BR.NTPC-22
June 8, 2012 Page 3 of 10
(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
NWT Public Utilities Board
BR.NTPC-22
June 8, 2012 Page 4 of 10
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
NWT Public Utilities Board
BR.NTPC-22
June 8, 2012 Page 5 of 10
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
NWT Public Utilities Board
BR.NTPC-22
June 8, 2012 Page 6 of 10
(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
NWT Public Utilities Board
BR.NTPC-22
June 8, 2012 Page 7 of 10
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
NWT Public Utilities Board
BR.NTPC-22
June 8, 2012 Page 8 of 10
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
NWT Public Utilities Board
BR.NTPC-22
June 8, 2012 Page 9 of 10
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
NWT Public Utilities Board
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
NWT Public Utilities Board
BR.NTPC-23
June 8, 2012 Page 1 of 25
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
NWT Public Utilities Board
BR.NTPC-23
June 8, 2012 Page 2 of 25
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
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June 8, 2012 Page 3 of 25
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.
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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.
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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.
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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
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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
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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
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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.
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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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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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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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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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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
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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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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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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
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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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• 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:
Prepared for the Northwest Territories Power Corporation by
Rescan Environmental Services Ltd.
• 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.
• Rescan Environmental Services Ltd. 2003. Taltson Hydro Project
2003: Water Effects Monitoring Program. Vancouver, BC:
Prepared for the Northwest Territories Power Corporation by
Rescan Environmental Services Ltd.
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• Rescan. 2003. Taltson Hydroelectric Expansion Project, 2003
Baseline Report. Northwest Territories Power Corporation.
• Rescan Environmental Services Ltd. 2004. Taltson Hydro Project
2004: Water Effects Monitoring Program. Vancouver, BC:
Prepared for the Northwest Territories Power Corporation by
Rescan Environmental Services Ltd.
• Rescan Environmental Services Ltd. 2006. Taltson Hydro Project
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.
Information Request
NTPC GRA 2012/13 and 2013/14
NWT Public Utilities Board
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.
Information Request
NTPC GRA 2012/13 and 2013/14
NWT Public Utilities Board
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
NWT Public Utilities Board
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
Information Request
NTPC GRA 2012/13 and 2013/14
NWT Public Utilities Board
BR.NTPC-23
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
NTPC GRA 2012/13 and 2013/14
NWT Public Utilities Board
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
NWT Public Utilities Board
BR.NTPC-24
June 8, 2012 Page 1 of 3
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
NWT Public Utilities Board
BR.NTPC-24
June 8, 2012 Page 2 of 3
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
Information Request
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NWT Public Utilities Board
BR.NTPC-24
June 8, 2012 Page 3 of 3
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
Information Request
NTPC GRA 2012/13 and 2013/14
NWT Public Utilities Board
BR.NTPC-26
June 8, 2012 Page 1 of 3
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.
Information Request
NTPC GRA 2012/13 and 2013/14
NWT Public Utilities Board
BR.NTPC-26
June 8, 2012 Page 2 of 3
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
Information Request
NTPC GRA 2012/13 and 2013/14
NWT Public Utilities Board
BR.NTPC-26
June 8, 2012 Page 3 of 3
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.
Information Request
NTPC GRA 2012/13 and 2013/14
NWT Public Utilities Board
BR.NTPC-27
June 8, 2012 Page 1 of 3
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)
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.
Information Request
NTPC GRA 2012/13 and 2013/14
NWT Public Utilities Board
BR.NTPC-27
June 8, 2012 Page 2 of 3
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
Information Request
NTPC GRA 2012/13 and 2013/14
NWT Public Utilities Board
BR.NTPC-27
June 8, 2012 Page 3 of 3
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.
Information Request
NTPC GRA 2012/13 and 2013/14
NWT Public Utilities Board
BR.NTPC-28
June 8, 2012 Page 1 of 20
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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Schedule B.1-Corporate Head Office:
Replace Upgrade IT Equipment
Schedule B.2-Snare Zone:
Packaged Sewage Treatment System
Snare Rapids Plant Upgrade
Schedule B.2-Taltson Zone:
Relocate Standby D&F Tanks
Schedule B.2-Thermal Zone:
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.
Information Request
NTPC GRA 2012/13 and 2013/14
NWT Public Utilities Board
BR.NTPC-28
June 8, 2012 Page 3 of 20
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
Information Request
NTPC GRA 2012/13 and 2013/14
NWT Public Utilities Board
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June 8, 2012 Page 4 of 20
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.
Schedule B.1-Snare Zone:
Snare Rapids Plant Upgrade
Original Budget: $0.658 million
Final Cost: $1.434 million
This response has been prepared to address a number of interrogatories which are
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.
Information Request
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NWT Public Utilities Board
BR.NTPC-28
June 8, 2012 Page 5 of 20
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
Information Request
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June 8, 2012 Page 6 of 20
SCADA system the headgate can be lowered remotely from the central control center at
Jackfish.
Bluefish Power Tunnel Upgrade
Original Budget: $0.227 million
Final Cost: $0.447 million
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
Original Budget: $0.060 million
Final Cost: $0.091 million
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
Original Budget: $0.139 million
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.
Schedule B.1-Taltson Zone:
Construct Winter Road
Please refer to the Corporation’s response to NUL.NTPC-3.
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Schedule B.1-Thermal Zone:
Fuel System Upgrade – Tuktoyaktuk
Original Budget: $0.245 million
Final Cost: $0.901 million
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
Original Budget: $0.139 million
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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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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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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(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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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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• 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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(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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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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Attachment BR.NTPC-28(b) – 1
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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Attachment BR.NTPC-28(b) – 2
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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Attachment BR.NTPC-28(b) – 3
Actual Capital Additions 2008/09 ($000s)
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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Attachment BR.NTPC-28(b) – 3 Con’t
Actual Capital Additions 2008/09 ($000s)
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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Attachment BR.NTPC-28(b) – 4
Actual Capital Additions 2009/10 ($000s)
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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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
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