SCHEDULE 1.0-T
ATCO Electric Transmission (AET)
SUMMARY OF REVENUE REQUIREMENT
FOR THE YEAR ENDED DECEMBER 31, 2014
($Millions)
Line
No.
Description
1
2
3
4
5
6
7
Return on Rate Base
Fuel
Operating and Maintenance
Depreciation and Amortization
Utility Income Tax
Subtotal
8
9
10
11
12
13
14
15
16
17
18
Revenue Offsets
Total Transmission Revenue Requirement
Detailed Revenue Requirement
Transmission Tariff Revenue
Deferral Account
Total Transmission Revenue Requirement
CrossReference
Sch 2.0-T
Sch 3.0-T
Sch 4.0-T
Sch 5.0-T
2014
Actual
294.0
8.3
114.8
130.9
22.4
570.4
(6.7)
2014
Approved *
274.3
6.3
127.3
134.4
27.7
570.0
(3.7)
2013
Actual **
248.3
6.8
105.2
105.4
24.8
490.5
(3.4)
Var. Actual to
Approved
Var.
%
Var. Actual to
Prior Year
Var.
%
19.6
2.0
(12.4)
(3.5)
(5.4)
0.4
7.2%
31.9%
-9.8%
-2.6%
-19.3%
0.1%
45.7
1.5
9.6
25.4
(2.4)
79.8
18.4%
21.9%
9.2%
24.1%
-9.6%
16.3%
(3.0)
81.9%
(3.4)
100.7%
76.5
15.7%
76.8
(0.3)
76.5
15.9%
-12.9%
15.7%
Sch 10
563.6
566.3
487.1
(2.7)
-0.5%
Line 10
561.4
2.2
563.6
566.3
566.3
484.6
2.5
487.1
(4.9)
2.2
(2.7)
-0.9%
100.0%
-0.5%
Working Paper
Reference
Note 1
Note 2
Note 3
Variance Explanations
* - 2014 Approved Per AUC Decision 2014-348 on ATCO Electric's 2013-2014 GTA Compliance Filing. These Approved figures were then subsequently adjusted for AUC Decision
D2191-D01-2015 on the 2013 Generic Cost of Capital. See separate schedules for specific adjustments and variance explanations.
** - 2013 Actuals have been restated from the prior year Rule 005 filing to align with AUC Decision 2014-348 on ATCO Electric's 2013-2014 GTA Compliance Filing.
Note 1
The actuals are higher than Forecast by $2.0. Of this variance, $0.9 is due to the reduction in the AUC approved forecast fuel cost. The remaining variance of $1.1 between the actual
and forecast (AET applied for forecast) costs is due to higher diesel fuel price ($0.6), higher natural gas fuel price ($0.5), and higher natural gas fuel volume ($0.2) partially offset by
lower diesel fuel volume ($0.2).
Note 2
2014 Actuals are higher than Forecast by $3.0 mainly due to higher revenue from ATCO Electric Distribution for telecom, isolated generation services, field,
commissioning and technical services ($3.3), Services to Outside Parties Revenue mostly from fuel at Little Horse ($0.7) offset by lower revenue from other ATCO affiliates ($1.0).
Note 3
The variance from 2014 Actual to Forecast is mainly due to higher capital expenditures on direct assigned projects resulting in a collection from the AESO for the transmission capital
deferral ($10.4). This collection balance is partially offset by refund balances owing relating to property taxes ($6.0) and the debenture rate ($1.9). Balances accumulated in the
deferral account will be refunded to the AESO in ATCO Electric's 2014 Transmission Deferral Application.
AUC Rule 005
SCHEDULE 2.0-T
ATCO Electric Transmission (AET)
SUMMARY OF RETURN ON RATE BASE
FOR THE YEAR ENDED DECEMBER 31, 2014
($Millions)
2014 Actuals
Line
No.
Description
CrossReference
1
Mid Year Rate Base (Farms, Irrigation Transmission)
2
3
4
Mid Year Rate Base
Long-Term Debt
Preferred Shares
5
6
7
8
9
Common Equity
Mid-Year Net Rate Base
Contribution for Extensions
No Cost Capital
Mid Year Rate Base
Mid-Year
Capital
Ratio
Prorated
Rate Base
Cost Rate
%
Return $
20.8
6.45%
1.3
Var. Actual to
Approved
Var.
%
Working Paper
Reference
Sch 2.2-T
Sch 2.2-T
2,613.9
133.6
60.89%
3.11%
2,819.3
144.1
4.84%
5.33%
136.4
7.7
5.1
(2.1)
3.9%
-21.1%
Note 1
Sch 2.2-T
Sch 1.0-T
1,545.4
4,292.9
36.00%
100.00%
1,666.9
4,630.2
411.9
74.4
5,116.6
8.91%
6.35%
148.5
294.0
16.7
19.7
12.7%
Note 2
Sch 2.1-T
2014 Approved
Line
No.
Description
Cross
Reference
10
Mid Year Rate Base (Farms, Irrigation Transmission)
11
12
13
14
15
16
17
18
19
20
Mid Year Rate Base
Long-Term Debt
Preferred Shares
Common Equity
Mid-Year Net Rate Base
Contribution for Extensions
No Cost Capital
Mid Year Rate Base
Sch 2.2-T
Sch 2.2-T
Sch 2.2-T
Sch 1.0-T
Sch 2.1-T
Mid Year
Capital
2,583.9
175.0
1,551.8
4,310.7
Deemed
Structure
59.94%
4.06%
36.00%
100.00%
Prorated
Rate Base
Cost Rate
%
Return $
25.7
5.48%
1.4
2,644.4
179.1
1,588.2
4,411.7
398.7
74.1
4,884.5
4.97%
5.44%
8.30%
6.22%
131.4
9.7
131.8
274.3
Return Variance
Note 1
In 2014 the Series 6.50% (Series 2) issue was retired.
Note 2
2014 Return on Common equity is higher than Forecast mainly due to lower O&M, depreciation and income tax expense .
AUC Rule 005
2
SCHEDULE 2.1-T
ATCO Electric Transmission (AET)
SUMMARY OF MID-YEAR RATE BASE
FOR THE YEAR ENDED DECEMBER 31, 2014
($Millions)
Line
No.
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
Description
CrossReference
2014
Actual
2014
Approved
2013
Actual
Var. Actual to
Approved
Var.
%
Var. Actual to
Prior Year
Var.
%
Gross Utility Plant in Service
Opening Balance
Closing Balance
Mid-Year Gross Utility Plant in Service
Sch 4.1-T
Sch 4.1-T
4,140.5
4,611.0
4,375.8
4,189.0
4,689.3
4,439.2
3,033.6
4,137.2
3,585.4
(48.5)
(78.3)
(63.4)
-1.2%
-1.7%
-1.4%
1,106.9
473.8
790.4
36.5%
11.5%
22.0%
Accumulated Depreciation - Utility
Opening Balance
Closing Balance
Mid-Year Accumulated Depreciation - Utility
Sch 4.1-T
Sch 4.1-T
847.7
939.1
893.4
863.1
988.2
925.6
763.1
847.7
805.4
(15.4)
(49.1)
(32.2)
-1.8%
-5.0%
-3.5%
84.6
91.4
88.0
11.1%
10.8%
10.9%
296.0
382.2
339.1
293.7
373.3
333.5
244.3
296.0
270.2
2.3
8.9
5.6
0.8%
2.4%
1.7%
51.7
86.2
68.9
21.2%
29.1%
25.5%
25.1
31.6
28.4
25.8
32.5
29.2
20.6
25.1
22.9
(0.7)
(0.9)
(0.8)
-2.8%
-2.7%
-2.7%
4.5
6.5
5.5
21.8%
26.0%
24.1%
3,171.6
3,209.2
2,532.7
(37.6)
-1.2%
638.9
25.2%
34.0
35.4
31.7
(1.4)
-3.9%
2.3
7.3%
(74.4)
(74.1)
(43.9)
(0.2)
0.3%
(30.5)
69.4%
(39.2)
-1.2%
610.8
24.2%
Contributions in Aid of Construction
Opening Balance
Closing Balance
Mid-Year Utility Contributions in Aid of Construction
Amortization of Contributions
Opening Balance
Closing Balance
Mid-Year Utility Amortization of Contributions
Mid-Year Net Utility Plant in Service
Necessary Working Capital
No Cost Capital
Mid-Year Net Rate Base
3,131.2
3,170.5
2,520.4
Mid-Year Direct Assigned CWIP
1,600.2
1,335.6
1,170.9
Mid-Year Contributions CWIP
Total Mid-Year Rate Base and CWIP
(101.2)
Sch. 2.0-T
4,630.2
(94.4)
4,411.7
Working Paper
Reference
(61.1)
3,630.3
AUC Rule 005 3
SCHEDULE 2.2-T
ATCO Electric Transmission (AET)
SUMMARY OF MID-YEAR CAPITAL STRUCTURE
FOR THE YEAR ENDED DECEMBER 31, 2014
($Millions)
Line
No.
Description
Cross-
Current
Previous
Actual
Forecast
Var. Actual to
Var.
Working Paper
Reference
Year-End
Year-End
Mid-Year Capital
Mid-Year Capital
Approved
%
Reference
1
Long-Term Debt
Sch 2.3
2,969.5
2,258.2
2,613.9
2,583.9
2
Preferred Shares
Sch 2.4
91.4
175.8
133.6
175.0
(41.4)
30.0
-23.7%
1.2%
3
Common Equity
1,721.7
1,369.1
1,545.4
1,551.8
(6.4)
-0.4%
Total Mid-Year Invested Capital
4,782.6
3,803.1
4,292.9
4,310.7
(17.8)
-0.4%
Note 1
4
5
Note 1
In 2014 the Series 6.50% (Series 2) issue was retired.
AUC Rule 005 4
SCHEDULE 2.3
ATCO Electric Transmission (AET)
SCHEDULE OF DEBT CAPITAL EMPLOYED
FOR THE YEAR ENDED DECEMBER 31, 2014
($Millions)
2014 Actual
Line
No.
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
CrossReference
Description
LT Adv. -Parent
Short-term Debt
2014 Ending Balance
2014 Opening Balance
Mid-Year Balance
Series
Issue
Date
Maturity
Date
Coupon
Rate
Principal
Amount
Y
Z
AA
1999
6.145
2004
2004
2005
2006
2006
2007
2008
2008
2009
2009
2010
2011
2011
2012
2012
2012
2013
2013
2013
2014
2014
1990-11-30
1991-12-18
1992-12-08
1999-08-01
2002-12-02
2004-01-23
2004-11-18
2005-11-30
2006-11-20
2006-11-20
2007-11-01
2008-05-26
2008-05-26
2009-03-06
2009-03-07
2010-11-10
2011-10-24
2011-10-24
2012-09-10
2012-09-10
2012-11-14
2013-09-09
2013-09-18
2013-11-07
2014-09-05
2014-10-17
2020
2022
2023
2019
2017
2019
2034
2035
2021
2036
2037
2028
2038
2024
2039
2050
2041
2061
2042
2062
2052
2043
2063
2053
2044
2054
11.770%
9.920%
9.400%
6.800%
6.145%
5.432%
5.896%
5.183%
4.801%
5.032%
5.556%
5.563%
5.580%
6.215%
6.500%
4.947%
4.543%
4.593%
3.805%
3.825%
3.857%
4.722%
4.855%
4.558%
4.085%
4.094%
22.4
29.3
13.8
43.1
46.9
34.3
71.0
56.3
59.2
59.2
79.1
29.3
44.0
68.0
85.6
73.3
192.6
77.0
319.9
127.8
162.4
241.0
75.0
225.0
555.0
180.0
1.500%
15.00
Underwriting
Discount
& Expense
0.2
0.4
0.1
0.3
0.3
0.2
0.4
0.4
0.3
0.4
0.5
0.2
0.3
0.4
0.6
0.5
1.2
0.5
2.0
0.8
1.0
1.5
0.6
1.4
3.3
1.2
Total
Amount
22.2
28.9
13.6
42.8
46.6
34.1
70.5
55.9
58.9
58.8
78.6
29.1
43.7
67.5
85.0
72.7
191.4
76.5
317.9
127.0
161.4
239.5
74.4
223.6
551.7
178.8
15.00
Effective
Cost Rate
%
11.83%
9.99%
9.46%
6.84%
6.19%
5.48%
5.94%
5.23%
4.85%
5.07%
5.60%
5.62%
5.63%
6.28%
6.56%
5.00%
4.54%
4.59%
3.86%
3.86%
3.90%
4.78%
4.91%
4.61%
4.09%
4.14%
1.50%
Principal
Outstanding
at Year-End
Average
Embedded
Cost Rate
Carrying
Cost
22.4
29.2
13.8
43.0
46.8
34.2
70.7
56.0
59.1
58.9
78.8
29.2
43.7
67.7
85.1
72.8
191.5
76.6
318.1
127.0
161.5
239.6
74.5
223.6
551.8
178.9
2,954.5
2.6
2.9
1.3
2.9
2.9
1.9
4.2
2.9
2.9
3.0
4.4
1.6
2.5
4.3
5.6
3.6
8.8
3.5
12.3
4.9
6.3
11.5
3.7
10.3
22.6
7.4
140.8
15.0
0.2
2,969.5
2,258.2
2,613.9
141.0
112.0
126.5
4.77%
4.75%
4.96%
4.84%
SCHEDULE 2.3
ATCO Electric Transmission (AET)
SCHEDULE OF DEBT CAPITAL EMPLOYED
FOR THE YEAR ENDED DECEMBER 31, 2014
($Millions)
2014 Approved
Line
No.
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
CrossReference
Description
LT Adv. - Parent
AUC Directions 69 & 74
AUC Directions 69 & 74
Issue
Date
Maturity
Date
Coupon
Rate
Principal
Amount
1990-11-30
1991-12-18
1992-12-08
1999-08-01
2002-12-02
2004-01-23
2004-11-18
2005-11-30
2006-11-20
2006-11-20
2007-11-01
2008-05-26
2008-05-26
2009-03-06
2009-03-07
2010-11-10
2011-10-24
2011-10-24
2012-09-10
2012-09-10
2012-11-14
2020
2022
2023
2019
2017
2019
2034
2035
2021
2036
2037
2028
2038
2024
2039
2050
2041
2061
2042
2062
2052
2043
2044
11.770%
9.920%
9.400%
6.800%
6.145%
5.432%
5.896%
5.183%
4.801%
5.032%
5.556%
5.563%
5.580%
6.215%
6.500%
4.947%
4.543%
4.593%
3.805%
3.825%
3.857%
4.745%
4.745%
22.4
29.3
13.8
43.1
46.9
34.3
71.0
56.3
59.2
59.2
79.1
29.3
44.0
68.0
85.6
73.3
192.6
77.0
319.8
127.8
162.5
679.1
416.6
Series
Y
Z
AA
1999
6.145
2004
2004
2005
2006
2006
2007
2008
2008
2009
2009
2010
2011
2011
2012
2012
2012
2013
2014
Short-term Debt
Notes Payable
Less: 2012 Subsidiary Debt Financing
2014 Ending Balance
2014 Opening Balance
Mid-Year Balance
0.250%
2.0
Underwriting
Discount
& Expense
0.2
0.4
0.1
0.3
0.3
0.2
0.4
0.4
0.3
0.4
0.5
0.2
0.3
0.4
0.6
0.5
1.2
0.5
2.0
0.8
1.0
4.1
2.5
Total
Amount
22.2
28.9
13.6
42.8
46.6
34.1
70.5
55.9
58.9
58.8
78.6
29.1
43.7
67.5
85.0
72.7
191.4
76.5
317.9
127.0
161.4
675.0
414.1
2.0
Effective
Cost Rate
%
11.81%
9.98%
9.44%
6.84%
6.19%
5.48%
5.93%
5.22%
4.85%
5.07%
5.60%
5.61%
5.63%
6.28%
6.56%
5.00%
4.60%
4.63%
3.86%
3.86%
3.90%
4.79%
4.78%
0.25%
Principal
Outstanding
at Year-End
Average
Embedded
Cost Rate
Carrying
Cost
22.4
29.2
13.8
43.0
46.8
34.2
70.7
56.0
59.1
58.9
78.8
29.2
43.7
67.7
85.1
72.8
191.5
76.6
318.1
127.0
161.5
675.2
414.1
2,776.0
2.6
2.9
1.3
2.9
2.9
1.9
4.2
2.9
2.9
3.0
4.4
1.6
2.5
4.3
5.6
3.6
8.8
3.5
12.3
4.9
6.3
32.4
19.8
137.6
2.0
0.0
4.8
0.2
3.87%
2,773.2
2,394.6
2,583.9
137.4
119.4
128.4
4.95%
4.98%
4.97%
4.96%
SCHEDULE 2.4
ATCO Electric Transmission (AET)
SCHEDULE OF PREFERRED SHARE CAPITAL EMPLOYED
FOR THE YEAR ENDED DECEMBER 31, 2014
($Millions)
2014 Actual
Line
No.
CrossReference
1
2
3
4
5
6
7
8
9
Series
Issue
Date
Dividend
Rate
4.70%
4.60%
3.80%
2007
2007
2010
4.00%
4.60%
3.80%
Current Year-End Balance
Prior Year-End Balance
Total
Mid-Year Balance
Stated
Value of
Issue
Underwriting
Discount
& Expense
Net Proceeds
Outstanding
Carrying
Cost of
Issue
Average
Embedded
Cost Rate
27.9
38.9
24.9
0.1
0.1
27.9
38.7
24.8
1.1
1.9
1.1
4.00%
4.89%
4.32%
91.7
176.5
268.2
134.1
0.2
0.6
91.4
175.8
267.2
133.6
4.1
10.2
14.2
7.1
4.47%
5.78%
5.33%
5.33%
Stated
Value of
Issue
Underwriting
Discount
& Expense
Variance
Actual to
Forecast
Var.
Working Paper
Reference
%
-
0%
0%
0%
2014 Approved
Line
No.
CrossReference
Carrying
Cost of
Issue
Average
Embedded
Cost Rate
Series
10
11
12
4.70%
4.60%
6.50%
2007
2007
2009
4.00%
4.60%
4.80%
27.9
38.9
84.8
0.1
0.4
27.9
38.8
82.9
1.3
1.9
4.5
4.53%
4.89%
5.42%
13
14
15
16
17
18
3.80%
2010
3.80%
24.9
0.1
24.6
1.1
4.34%
176.5
176.5
353.0
176.5
0.7
0.6
174.2
175.8
349.9
175.0
8.7
10.3
19.0
9.5
5.01%
5.86%
5.44%
5.44%
Current Year-End Balance
Prior Year-End Balance
Total
Mid-Year Balance
Dividend
Rate
Net Proceeds
Outstanding
Issue
Date
AUC Rule 005 6
SCHEDULE 3.0-T
ATCO Electric Transmission (AET)
SUMMARY OF OPERATING AND MAINTENANCE EXPENSE
FOR THE YEAR ENDED DECEMBER 31, 2014
($Millions)
Line
No.
Acct
No.
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
560
561
562
563/569
566
567
571.1
575
34
35
36
37
38
39
40
41
42
43
44
45
46
Description
CrossReference
Direct Operation & Maintenance Expense
Supervision and Engineering
Control Centre Operations
Station Equipment Expenses
Overhead Lines Expenses & Operation Maintenance
Miscellaneous Transmission Expense
Right of Way Payments
Vegetation Management
IT Support
Disallowed/Non-Utility Costs (included above)
Sponsorships, Donations
Earnings Component of Executive Compensation
Isolated Generation Operation & Maintenance
Total Operation and Maintenance Costs
Allocated Administrative and General
Taxes Other Than Income
Sch 3.1-T
Farms, Irrigation Transmission Operating Costs
Total Transmission O&M Costs
Sch 1.0-T
2014
Actual
2014
Approved
2013
Actual
Var. Actual to
Approved
Var.
%
Var. Actual to
Prior Year
Var.
%
Working Paper
Reference
5.4
3.1
13.2
4.5
9.8
5.2
3.8
3.7
48.9
5.3
4.4
13.7
4.8
12.0
4.4
6.2
4.0
54.7
4.5
3.1
11.2
4.7
9.3
3.3
5.6
3.1
44.8
0.1
(1.3)
(0.4)
(0.3)
(2.1)
0.8
(2.4)
(0.3)
(5.9)
2.5%
-30.1%
-3.0%
-6.2%
-17.8%
17.7%
-38.2%
-6.3%
-10.7%
1.0
(0.0)
2.1
(0.2)
0.5
1.9
(1.8)
0.6
4.0
21.6%
-1.4%
18.7%
-3.7%
5.5%
56.8%
-31.9%
18.6%
9.0%
48.9
(0.1)
54.7
(0.1)
(0.0)
44.7
0.1
(5.8)
0.0%
-100.0%
-10.6%
0.1
0.0
4.2
-100.0%
-100.0%
9.3%
7.6
7.6
7.5
7.5
6.9
6.9
0.0
0.0
0.4%
0.4%
0.6
0.6
9.1%
9.1%
56.4
62.2
51.7
(5.8)
-9.4%
4.7
9.0%
25.9
31.5
57.4
26.2
37.5
63.7
25.7
27.0
52.7
(0.3)
(6.0)
(6.4)
-1.2%
-16.1%
-10.0%
0.2
4.5
4.7
1.0%
16.5%
8.9%
113.8
126.0
104.3
(12.2)
-9.7%
9.4
9.0%
1.0
1.3
0.9
(0.3)
-21.9%
0.2
18.4%
114.8
127.3
105.2
(12.5)
-9.8%
9.5
9.1%
Note 1
Note 2
Note 3
Note 4
Variance Explanations
Note 1
2014 Actuals are lower than Forecast by $1.3 mainly due to vacancies ($1.4) offset by higher than forecast overtime required ($0.1).
Note 2
2014 Actuals are lower than Forecast by $2.1 mainly due to lower equipment hours ($0.6), VPP ($0.6), greater than forecast recoveries associated with affiliate work ($0.4) and Services to
Outside Parties (0.1), travel and meals ($0.3), supervision activities related to Reliability Compliance charged to 560 to better align with minimum filing requirements ($0.2), training fees ($0.2),
rent expense ($0.2), increased capital work in Cyber Security ($0.1), relocation costs($0.1) and material (0.1). This was partially offset by higher than forecast building
expenses ($0.3), surface rentals ($0.2), labour escalation ($0.2) and telephone and fax ($0.1).
Note 3
2014 Actuals are lower by $2.4 than Forecast mainly due to a reduction in the completion of mow and spray programs due to contractor availability ($2.6), a reduced requirement for
facility (substation, tower and remote operations) vegetation management ($0.2) due to a lower than average emergence of weeds in treatment areas, and a reduction in the need for
trim operations due to a permanent removal of trim sites ($0.2). This was partially offset by an increase in critical clearance site treatment ($0.4), and an increase in slash
operations costs due to difficult terrain encountered ($0.2).
Note 4
2014 Actuals are lower than Forecast by $6.0 mainly due to lower capital additions and lower inflation on the Assessment Year Modifier. The lower taxes other than income will be
refunded to the AESO in ATCO Electric's 2014 Deferral Application.
AUC Rule 005 7
SCHEDULE 3.1-T
ATCO Electric Transmission (AET)
SUMMARY OF OPERATING AND MAINTENANCE EXPENSE (CORPORATE)
FOR THE YEAR ENDED DECEMBER 31, 2014
($Millions)
Line
No.
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
Acct.
No.
920
921
923
924
925
928
930.2
931.1
934
941
935.2
Description
Direct Operation & Maintenance Expense
General Administration
Office Supplies and Expenses
Outside Services Employed
Insurance Premiums
Injuries and Damages
Board Expenses
Miscellaneous General Expenses
Head Office Rent
IT G&A Expense
Board Expenses Disallowed
Maintenance Company Owned Houses
CrossReference
`
Non-utility Items
Donations
Earnings Based Executive Compensation
Disallowed Head Office Costs
Corporate Signature Rights
Disallowed Aircraft
Legal Cost in Excess of Board Scale
Pension - COLA
IT Cost Reduction
Total Administration and General
Total Labour
Total Other
Total Administration and General
Sch 3.0-T
2014
Actual
2014
Approved
2013
Actual
Var. Actual to
Approved
Var.
%
Var. Actual to
Prior Year
Var.
%
6.0
7.1
0.6
2.8
1.0
0.4
8.6
1.0
3.0
1.0
0.2
31.6
6.3
4.5
1.0
2.5
1.0
0.4
7.0
2.3
2.2
0.1
0.3
27.7
6.8
5.6
0.8
2.0
1.0
0.4
7.6
2.5
2.5
0.7
0.3
30.2
(0.3)
2.6
(0.4)
0.3
(0.0)
1.6
(1.4)
0.8
0.8
(0.1)
4.0
-4.5%
57.3%
-36.1%
12.2%
0.0%
0.0%
22.4%
-57.9%
35.7%
727.4%
-34.6%
14.3%
(0.7)
1.5
(0.2)
0.7
(0.0)
0.9
(1.5)
0.5
0.2
(0.1)
1.4
-10.9%
26.9%
-20.5%
35.1%
0.0%
0.0%
12.2%
-60.1%
19.9%
33.9%
-29.7%
4.7%
(0.7)
(0.2)
(2.5)
(0.5)
(1.0)
(0.3)
(0.5)
(5.7)
(0.3)
(0.1)
(0.1)
(0.7)
(0.1)
(1.4)
(0.6)
(0.0)
(0.1)
(1.5)
(0.2)
(0.8)
(1.3)
(4.5)
(0.3)
0.1
(0.1)
(1.8)
(0.5)
(0.9)
(0.3)
(0.5)
(4.3)
93.1%
-100.0%
78.1%
233.9%
100.0%
755.7%
100.0%
100.0%
302.4%
(0.1)
0.0
(0.1)
(1.0)
(0.3)
(0.2)
0.9
(0.5)
(1.2)
16.5%
-100.0%
58.7%
63.4%
103.0%
31.5%
-73.0%
0.0%
25.7%
25.9
26.2
25.7
(0.3)
-1.2%
0.2
6.0
19.9
25.9
6.9
19.3
26.2
6.9
18.8
25.7
(0.8)
0.6
(0.3)
-12.2%
3.0%
-1.1%
(0.9)
1.1
0.2
Working Paper
Reference
Note 1
Note 2
Note 3
Note 4
1.0%
-12.8%
6.0%
0.9%
Variance Explanations
Note 1
The 2014 Actual is higher than Forecast by $2.6 mainly due to higher allocated Corporate Signature rights of ($1.8), higher charges for use of the corporate aircraft ($0.5) and
33
increased donations ($0.3). The higher costs for corporate signature rights and donations are adjusted for as part of the non-utility items in Line No. 17 & Line No. 14 respectively.
34
The higher corporate aircraft charges are offset by the calculated disallowance on Line No. 18 for the aircraft cost differential (in accordance with AUC Decision 2007-071 Direction 56).
35
36
37
38
39
40
41
42
Note 2
The 2014 Actual is higher than Forecast by $1.6 mainly due to higher allocated costs from ATCO Ltd and CU Limited of ($3.5) offset by lower allocated credit facility charges of ($0.2).
This variance is also offset by higher overhead recoveries of $(0.9) and lower Affiliate Cost of Goods Sold ($0.9) due to payroll services and financial support functions for ATCO
Electric affiliates now being solely provided by ATCO Electric Distribution. The lower Affiliate Cost of Goods Sold expense is offset by lower Affiliate Revenues.
Note 3
2014 Actual is lower than the Forecast by $1.4 due to higher rent charges charged to capital reflecting capital initiatives.
Note 4
Corporate Signature rights were not included in the 2014 Revenue requirement.
AUC Rule 005 18
SCHEDULE 4.0-T
ATCO Electric Transmission (AET)
SUMMARY OF DEPRECIATION EXPENSE
FOR THE YEAR ENDED DECEMBER 31, 2014
($Millions)
Line
No.
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
Description
CrossReference
2014
Actual
2014
Approved
2013
Actual
Var. Actual to
Approved
Var.
%
Var. Actual to
Prior Year
Var.
%
Transmission
Opening Rate Base Adjustment
Amortization of Differences
Subtotal
108.5
0.9
109.4
112.5
0.8
113.3
87.9
0.8
88.7
(4.0)
0.1
(3.9)
-3.5%
0.0%
7.3%
-3.5%
20.6
0.1
20.7
23.5%
0.0%
7.3%
23.3%
Direct General PP&E
Structures & Improvements
Office Furniture and Equipment
Computer Equipment
Transportation Equipment
Tools & Instruments
2.5
0.9
0.1
3.2
1.9
2.1
0.4
0.0
2.5
1.6
2.1
0.7
0.1
2.7
1.3
0.4
0.4
0.0
0.7
0.3
18.3%
102.1%
145.6%
28.2%
17.1%
0.4
0.2
(0.0)
0.5
0.6
19.9%
24.3%
-49.7%
18.6%
43.7%
Communication Equipment
Housing
Leasehold Improvements
Software
Amortization of Differences
Subtotal
5.9
0.0
1.1
6.7
(0.4)
21.8
7.0
1.6
3.3
(0.2)
18.4
4.7
0.6
3.1
(0.3)
15.0
(1.1) -16.0%
0.0
0.0%
(0.5) -32.1%
3.4 101.7%
(0.2) 95.7%
3.4 18.6%
1.2
0.0
0.5
3.6
(0.1)
6.8
25.6%
0.0%
75.7%
116.7%
30.4%
45.3%
Allocated General PP&E
-
1.8
-
(1.8) -100.0%
-
0.0%
-1.7%
27.5
26.5%
(0.4) -30.3%
0.1
20.9%
-2.0%
27.6
26.5%
Transmission Gross Provision
131.2
133.5
103.7
0.8
1.2
0.7
Total Transmission Gross Depreciation Expense
132.0
134.7
104.4
(2.7)
27
Depreciation Gross Provision - Life
108.1
117.1
84.0
(9.1)
-7.7%
24.1
28.7%
28
Depreciation Gross Provision - Net Salvage
24.0
17.6
20.4
6.4
36.4%
3.6
17.5%
132.0
134.7
104.4
(2.7)
-2.0%
27.6
26.5%
132.0
134.7
104.4
(2.7)
-2.0%
27.6
26.5%
Farms, Irrigation Transmission
(2.3)
Working Paper
Reference
26
29
30
31
Gross Depreciation Expense
32
Vehicle Depreciation Capitalized
(2.1)
(1.0)
(1.6)
33
Amortization of Contributions
(6.6)
(6.9)
(4.7)
0.2
34
Total Depreciation and Amortization Expense
(1.1) 108.5%
(0.5)
30.3%
-3.4%
(1.9)
39.8%
123.3
126.8
98.0
(3.5)
-2.8%
25.3
25.8%
7.6
7.6
7.4
-
0.0%
0.2
2.2%
130.9
134.4
105.4
(3.5)
-2.6%
25.4
24.1%
Note 1
35
36
Pension Contributions Capitalized
37
38
Total Depreciation and Amortization Expense
(including Pension contributions capitalized)
Sch 1.0-T
39
40
Note 1
Variance explanation
2014 Actual depreciation expense is lower than Forecast mainly due to lower additions primarily related to capital maintenance projects as well as timing of capital additions.
AUC Rule 005 8
SCHEDULE 4.1-T
ATCO Electric Transmission (AET)
CAPITAL ASSETS CONTINUITY SCHEDULE
FOR THE YEAR ENDED DECEMBER 31, 2014
($Millions)
CAPITAL ASSETS
Line
No.
Property Group
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
Transmission
Subtotal - Utility Plant in Service
Balance at
12/31/2013
3,782.1
Direct General PP&E
Land
Structures and Improvements
Office Furniture and Equipment
Computer Equipment
Transportation Equipment
Tools and Instruments
Communication Equipment
Housing
Leasehold Improvements
Software
Subtotal
2.0
106.5
7.5
0.3
44.5
15.0
127.5
0.0
14.3
40.8
358.4
Sch 2.1-T
2014
Additions
396.8
5.4
14.7
4.6
(0.0)
13.1
5.5
24.4
0.2
6.7
13.9
88.5
2014
Retirements
2014
Transfers
2014
Adjustments
2014
AFUDC *
Balance at
12/31/2014
(13.4)
-
0.7
-
4,166.2
(0.2)
(0.2)
(0.0)
(0.8)
(0.9)
(0.0)
(2.1)
-
-
-
7.4
121.1
12.0
0.2
56.8
19.6
151.9
0.2
21.0
54.7
444.8
4,140.5
485.3
(15.5)
-
0.7
-
4,611.0
Capital Work in Progress (CWIP)
1,323.5
688.5
-
-
-
-
2,012.0
Total Transmission
5,464.1
1,173.8
(15.5)
-
0.7
-
6,623.0
ACCUMULATED DEPRECIATION
Line
No.
Property Group
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
CrossReference
CrossReference
Transmission
748.3
Direct General PP&E
Land
Structures and Improvements
Office Furniture and Equipment
Computer Equipment
Transportation Equipment
Tools and Instruments
Communication Equipment
Housing
Leasehold Improvements
Software
Subtotal
Total Transmission
Balance at
12/31/2013
(0.1)
12.2
2.0
0.2
10.0
3.4
55.9
0.3
5.1
10.5
99.5
Sch 2.1-T
847.7
Depreciation
Provision
2014
Retirements
2014
2014
Net Salvage Adjustments
2014
AFUDC
Balance at
12/31/2014
108.8
(13.4)
(23.8)
0.6
-
820.5
2.5
0.9
0.0
3.2
1.9
5.5
1.1
6.7
21.8
(0.2)
(0.2)
(0.0)
(0.8)
(0.9)
(0.0)
(2.1)
0.1
(0.6)
(0.5)
-
-
(0.1)
14.4
2.7
0.2
12.5
4.5
60.8
0.3
6.1
17.2
118.6
130.6
(15.5)
(24.3)
0.6
-
939.1
Working Paper
Reference
Working Paper
Reference
* AFUDC is a component of all categories except Direct Assigned CWIP and is therefore not disclosed separately in this continuity schedule.
AUC Rule 005 9
SCHEDULE 4.2-T
Page 1 of 5
ATCO Electric Transmission (AET)
SUMMARY OF CAPITAL EXPENDITURES & ADDITIONS
FOR THE YEAR ENDED DECEMBER 31, 2014
($Millions)
2014 Actual
Line
No.
Project
1
Description
CWIP
Balance
Cap
Expend
2014 Approved
Cap
Adds
CWIP
Balance
CWIP
Balance
Cap
Expend
Cap
Adds
CWIP
Balance
Higher/(Lower)
Expenditures Actual
to Approved
Var.
%
Higher/(Lower)
Addition Actual
to Approved
Var.
%
CAPITAL MAINTENANCE
2
50010
Transmission Capital Maintenance - Substations
9.5
10.9
4.1
16.4
10.5
7.1
6.7
10.9
3.8
54%
(2.6)
-39%
3
50020
Transmission Capital Maintenance - Lines
5.8
17.3
3.8
19.4
8.8
7.9
14.4
2.3
9.4
119%
(10.6)
-74%
4
50040
Transmission System Right-of-Way
0.1
1.3
1.2
0.2
-
3.3
3.3
-
(2.1)
-62%
(2.2)
-65%
5
50041
Transmission Rights-of-Way Widening
2.2
3.4
5.3
0.3
-
5.7
5.7
-
(2.3)
-41%
(0.5)
-8%
6
50060
Substation Rebuilds
5.1
9.4
10.9
3.6
6.8
12.9
18.7
1.1
(3.5)
-27%
(7.7)
-41%
7
50130
Replace or Rebuild Major Transmission Apparatus
2.4
5.3
3.4
4.3
4.2
4.7
4.4
4.6
0.6
13%
(1.0)
-22%
8
50170
Transmission Emergency Apparatus
0.6
0.4
0.5
0.5
0.2
2.2
0.3
2.2
(1.8)
-82%
0.3
108%
9
50190
Transmission Line Ground Clearance
0.2
0.5
0.6
0.1
(0.0)
4.3
4.3
(0.0)
(3.9)
-89%
(3.8)
-87%
10
50500
McNeill HVDC Control Replacement
11.8
1.4
0.0
13.2
-
-
-
-
1.4
100%
0.0
100%
123%
11
50940
Transmission Double Circuit
1.1
0.5
1.1
0.5
(0.0)
0.5
0.5
(0.0)
(0.0)
-1%
0.6
12
50960
Mitigate Equipment Problems
0.2
0.7
0.2
0.7
0.0
1.7
1.7
(0.0)
(1.0)
-59%
(1.5)
-89%
(0.2)
(0.4)
(0.4)
(0.1)
0.4
-100%
0.4
-100%
30.4
50.1
59.6
20.9
0.9
2%
(28.5)
-48%
13
AUC Direction 21 - Contractor Inflation
14
15
39.0
51.0
31.0
59.0
TELECOMMUNICATION
16
50400
Telecommunication Capital Maintenance
5.2
4.2
7.6
1.8
1.4
1.2
0.6
1.9
3.1
259%
7.0
17
59911
Telecom Site Power Backup
5.0
1.2
5.9
0.3
-
5.0
5.0
-
(3.8)
-76%
0.9
18
59943
Grande Prairie Area Telecom Reliability
-
0.0
-
0.0
1.1
1.2
2.3
-
(1.1)
-97%
(2.3)
0.3
1.8
(0.1)
19
59946
Mobile Communication System
1.7
-
0.1
83%
59948
Microwave Capacity Upgrade
1.7
1.3
2.4
0.6
1.2
1.2
2.4
(0.0)
0.1
12%
0.0
0%
21
59955
Network Mulitplexor Upgrade
3.0
3.4
4.5
1.9
-
3.3
3.3
-
0.1
3%
1.2
37%
16.3
10.4
22.2
4.6
AUC Direction 21 - Contractor Inflation
23
24
1.6
0.2
0.1
18%
-100%
20
22
1.4
1083%
5%
(0.0)
(0.1)
(0.1)
(0.0)
0.1
-100%
0.1
-100%
5.2
11.8
15.2
1.9
(1.4)
-12%
7.0
46%
SCADA / EMS
25
50800
Substation Control Expansion Program
0.1
0.0
-
0.1
-
-
-
-
0.0
100%
-
26
50900
Operational Information Systems
-
0.2
0.1
0.1
-
0.9
0.9
-
(0.7)
-77%
(0.8)
27
59919
Operational Cyber Security Project
0.8
1.2
1.9
0.0
-
-
28
AUC Direction 21 - Contractor Inflation
29
0%
-88%
2.0
2.0
(0.8)
-42%
(0.1)
0.0
(0.0)
(0.0)
0.0
0.0
-100%
0.0
-100%
(1.5)
-52%
(0.9)
-30%
(2.5)
-4%
(23.0)
-29%
0.9
1.4
2.0
0.3
0.0
2.9
2.9
0.0
-
-
-
-
-
0.6
0.6
-
56.2
62.9
55.2
63.8
35.6
65.4
78.2
22.8
-3%
30
31
AUC Direction 5 - Allocation of Non DA Capital VPP (IR AUC-AE-10)
32
33
TOTAL CAPITAL MAINTENANCE
34
35
DIRECT ASSIGNED PROJECTS SYSTEM
36
58001
Edmonton-Calgary 500 kV East Route
929.1
737.0
-
1,666.1
944.3
417.1
-
1,361.4
319.9
77%
-
37
58005
Southeast Bulk System Reinforcement
24.9
23.1
25.5
22.6
27.2
18.7
25.1
20.8
4.4
24%
0.4
0%
1%
38
51103
Arcenciel Synchronous Condenser
-
0.9
0.9
(0.0)
-
-
-
-
0.9
100%
0.9
100%
39
51718
Livock 240kV Phase Shifting Transformer Addition
-
0.3
0.3
0.0
-
-
-
-
0.3
100%
0.3
100%
40
53320
High Prairie to Triangle 144kV Line Upgrade
18.8
37.1
55.9
0.0
27.0
25.5
52.5
-
11.6
45%
3.4
6%
41
53600
New Little Smoky South 240kV Substation
-
0.0
-
0.0
-
-
-
-
0.0
100%
-
0%
42
53601
New Wembley 240 kV Substation
-
0.0
-
0.0
-
-
-
-
0.0
100%
-
0%
43
53603
Little Smoky South to Wembley 240 kV Line
-
0.0
-
0.0
-
-
-
-
0.0
100%
-
0%
44
53604
Seal Lake Expansion & 240kV Source
-
0.0
-
0.0
-
-
-
-
0.0
100%
-
0%
45
53605
Wesley Creek to Little Smoky South 240 kV Line
-
0.1
-
0.1
-
-
-
-
0.1
100%
-
0%
46
53750
Edith Lake to Sarah Lake 144kV Line Upgrade
-
0.1
0.1
(0.0)
-
-
-
-
0.1
100%
0.1
47
53751
Cordel to Tinchebray 240 kV Line
-
0.0
-
0.0
-
-
-
-
0.0
100%
-
0%
48
53753
Oakland to Lanfine 240 kV Line and Lanfine Transformer Addition
-
0.0
-
0.0
-
-
-
-
0.0
100%
-
0%
49
53754
Coyote Lake to Hanna 144kV Line and Hanna Conversion
-
0.0
-
0.0
-
-
-
-
0.0
100%
-
0%
50
53758
Pemukan to Monitor 144 kV Line and Pemukan Transformer Addition
-
0.0
-
0.0
-
-
-
-
0.0
100%
-
0%
51
54904
Jasper Transmission Interconnection
0.2
0.7
-
0.9
-
-
-
-
0.7
100%
-
52
54970
Otauwau 144kV Reinforcement
-
(0.1)
(0.1)
(0.0)
-
-
-
-
(0.1)
-100%
(0.1)
-100%
53
55001
Salt Creek - 240-144kv Substation
-
0.0
0.1
(0.1)
-
-
-
-
0.0
100%
0.1
100%
100%
0%
SCHEDULE 4.2-T
Page 2 of 5
ATCO Electric Transmission (AET)
SUMMARY OF CAPITAL EXPENDITURES & ADDITIONS
FOR THE YEAR ENDED DECEMBER 31, 2014
($Millions)
2014 Actual
Cap
Expend
Cap
Adds
CWIP
Balance
CWIP
Balance
CWIP
Balance
Higher/(Lower)
Addition Actual
to Approved
Var.
%
54
55125
Birchwood 240kV Line and Substation
8.1
20.8
-
28.9
13.6
60.5
74.1
(0.0)
(39.7)
-66%
(74.1)
-100%
55
55126
Ells – 9L76/9L08 240kV D/C Line
7.7
3.6
-
11.3
2.4
41.9
44.0
0.3
(38.3)
-91%
(44.0)
-100%
56
55127
9L95 Development
10.5
(3.0)
-
7.6
-
-
-
(3.0)
-100%
-
57
55322
Algar Area System Reinforcement
5.3
20.6
-
25.9
22.8
30.0
-
(2.2)
-10%
7.2
Cap
Adds
Var.
%
Project
-
Cap
Expend
Higher/(Lower)
Expenditures Actual
to Approved
Line
No.
Description
CWIP
Balance
2014 Approved
(30.0)
0%
-100%
58
55585
North Fort McMurray Transmission Development
-
2.9
2.9
(0.0)
-
-
-
-
2.9
100%
2.9
100%
59
55588
Kearl to McClelland L9900
-
0.2
0.2
(0.0)
-
-
-
-
0.2
100%
0.2
100%
60
55639
Purchase of Kearl 240 kV Line
-
0.0
-
0.0
0.1
-
-
0.1
0.0
100%
-
61
55703
Heart Lake Station Expansion
0.8
10.9
-
11.7
1.6
3.4
5.1
-
7.5
219%
(5.1)
(0.0)
(0.0)
0.0
(0.0)
-
-
(0.0)
(0.0)
-100%
(0.0)
-100%
-
1.1
0.6
1.9
0.0
2.6
(1.2)
-64%
(0.0)
-100%
12.4
100%
49.4
100%
3.1
-9442%
14.7
-44399%
62
55730
Livock 240 - 144kV Substation
-
63
55737
Thickwood Development
0.4
0.7
64
55785
Kettle River Substation and 240kV Line Tap
37.1
12.4
49.4
(0.0)
-
-
-
-
65
56539
Cold Lake Development
11.6
3.1
14.7
(0.0)
0.0
(0.0)
(0.0)
0.0
66
56760
Tinchebray - Vermillion Area Transmission Development Project
-
0.6
-
0.6
-
67
57102
7L50 Rebuild
0.5
-
-
0.5
5.5
68
57120
Central East Clearance Mitigation
4.4
(0.5)
0.0
3.9
69
57121
7L14 - Central East Clearance Mitigation
0.5
1.1
-
70
57130
Athabasca Area Transmission Development
0.1
0.0
-
71
57150
0.1
0.1
-
0.6
100%
-
-
27.5
(22.0)
-100%
-
-
-
-
-
(0.5)
-100%
0.0
1.6
-
-
-
0.1
5.2
5.7
0.0
0.0
100%
-100%
(0.0)
0%
-100%
-
-
0.1
100%
0.1
57151
St. Paul Area – Watt Lake and Whitby Lake Substations
3.4
1.9
5.3
(0.0)
-
8.0
8.0
-
(6.1)
-76%
(2.6)
-33%
Vermilion Cap Bank
-
0.3
0.3
(0.0)
-
-
-
-
0.3
100%
0.3
100%
74
57153
7L749 Rebuild
2.4
0.0
-
2.4
-
-
-
-
0.0
100%
-
75
57155
Cold Lake Area - Bourque-Bonnyville
59.2
65.9
108.5
16.6
-
40.0
40.0
-
25.9
65%
68.5
171%
76
57156
Kitscoty Area Development
11.7
13.3
25.0
(0.0)
-
-
-
-
13.3
100%
25.0
100%
77
57157
St. Paul Substation and Line
16.5
26.6
-
43.1
-
-
-
-
26.6
100%
-
0%
1,153.1
980.6
288.9
667.5
278.7
313.2
47%
10.2
4%
-
-
-
-
0.0
100%
-
0%
0.5
-
-
0.5
(0.0)
-100%
-
0%
1,034.8
-
1.1
(5.7)
0%
100%
57152
1,844.8
-
10.9
0%
72
TOTAL DIRECT ASSIGNED PROJECTS - SYSTEM
-
-
73
78
Heisler Area Development
22.0
0%
-100%
1,423.5
100%
0%
79
80
DIRECT ASSIGNED PROJECTS - CUSTOMER
81
51074
Fort Nelson Remedial Action Scheme
0.2
82
51161
LaCrete 144 kV Line & Substation
-
0.0
-
0.2
(0.0)
-
(0.0)
83
51162
Blumenort - Windy Hills 144kV Transmission Line
84
51168
Norcen Substation Capacity
1.3
0.1
-
1.4
0.5
-
-
0.5
0.1
100%
-
0%
0.1
0.6
-
0.7
-
-
-
-
0.6
100%
-
85
51181
0%
Carmon Creek Cogen
0.5
8.6
-
9.1
-
-
-
-
8.6
100%
-
86
51184
Swan Hills Synfuel Generation Interconnection
-
(0.0)
3.3
2.0
5.3
-
(2.0)
-100%
87
51341
Buchanan Creek Substation
8.7
88
51425
Harmon Valley POD
-
89
51440
Whitetail Peaking Station Interconnection
0.2
0.5
0.1
90
51680
Brintnell Permanent Capacity Addition
-
0.5
0.5
-
(5.3)
0%
(0.0)
(0.0)
1.3
10.0
0.0
8.0
1.4
9.4
-
(0.0)
-3%
0.6
7%
(0.0)
-
(0.0)
2.3
3.9
(0.0)
6.2
(3.9)
-100%
0.0
-100%
0.6
-
-
-
-
0.5
100%
0.1
100%
(0.0)
-
0.1
0.1
0.0
0.4
825%
0.5
861%
-
91
51745
Cavalier (Wabasca) 25kV Breaker Addition
0.1
0.2
0.2
-
-
-
-
0.2
100%
92
52025
Slave Lake Pulp Biomethanation
0.1
0.0
0.1
(0.0)
-
-
-
-
0.0
100%
0.1
93
52045
Muskwa Gas to Power Facility
-
0.6
-
0.6
-
-
-
-
0.6
100%
-
94
53011
Friedenstal Transformer Addition
-
(0.1)
(0.1)
0.0
-
-
-
-
(0.1)
-100%
95
53032
Ksituan River Voltage Regulator & 25 kV Breaker Addition
-
0.1
0.1
0.0
-
-
-
-
0.1
100%
96
53080
Crooked Creek POD
-
-
-
-
0.1
-
-
0.1
-
97
53440
Thornton New POD (Kakwa POD)
-
0.1
-
0.1
-
-
-
-
-100%
0%
100%
0%
(0.1)
-100%
0.1
100%
0%
-
0%
0.1
100%
-
0%
98
53593
Grande Prairie
-
0.1
-
0.1
-
-
-
-
0.1
100%
-
0%
99
54381
Mercer Hill Breaker Addition
0.2
1.0
-
1.2
-
-
-
-
1.0
100%
-
0%
100
54954
Maxim Power Generator Increase
-
0.0
-
0.0
-
-
-
-
0.0
100%
-
101
55010
Commercial Plant
-
-
-
-
0.1
3.1
0.0
3.2
(3.1)
-100%
102
55080
240 kV Line from 847S to Alternate Source
-
-
-
-
-
103
55147
9L66/9L32 Line Relocation
0.3
0.2
4.4
0.0
4.5
104
55187
Service for MacKay SAGD
4.3
105
55250
Joslyn North Mine 240 kV Connection
-
106
55325
Sweetheart Lake (Algar Expansion)
0.7
0.0
-
0.0
(0.3)
-
(0.0)
0.0
100%
(4.7)
-107%
(0.0)
(0.0)
0%
-100%
0%
-100%
9.7
-
13.9
1.6
2.8
4.5
-
6.8
239%
(4.5)
-100%
(0.0)
-
(0.0)
2.7
10.8
0.0
13.4
(10.8)
-100%
(0.0)
-100%
7.1
-
7.7
2.8
5.3
0.0
8.1
1.8
33%
(0.0)
-100%
SCHEDULE 4.2-T
Page 3 of 5
ATCO Electric Transmission (AET)
SUMMARY OF CAPITAL EXPENDITURES & ADDITIONS
FOR THE YEAR ENDED DECEMBER 31, 2014
($Millions)
2014 Actual
Cap
Expend
Cap
Adds
CWIP
Balance
CWIP
Balance
Cap
Expend
Cap
Adds
CWIP
Balance
Higher/(Lower)
Expenditures Actual
to Approved
Var.
%
Higher/(Lower)
Addition Actual
to Approved
Var.
%
Line
No.
Project
107
55579
Secord Substation
0.2
5.7
-
108
55584
Green Stocking Substation
-
0.0
0.0
109
55622
Cheecham POD
1.0
8.0
-
8.9
8.3
8.2
110
55631
Quigley 144kV Line and Substation
-
0.3
0.3
0.0
-
-
-
-
0.3
100%
111
55632
Surmount II (Stage 2)
31.5
3.0
34.5
0.0
-
-
-
-
3.0
100%
34.5
100%
112
55633
Surmount II (Stage 3)
0.9
17.0
-
17.9
3.1
9.8
0.2
7.2
74%
(12.7)
-100%
Description
CWIP
Balance
2014 Approved
6.0
-
-
-
-
5.7
100%
-
(0.0)
-
-
-
-
0.0
100%
0.0
100%
(16.5)
-100%
0.3
100%
16.5
12.7
0.0
(0.2)
-2%
113
55647
Joslyn Area New POD
0.1
(0.1)
-
(0.0)
-
-
-
-
(0.1)
-100%
-
114
55651
Egg Lake Substation and 144kv Line
0.9
(0.9)
-
(0.0)
1.5
4.5
0.0
6.0
(5.4)
-119%
(0.0)
5.2
18.3
115
55655
Bohn POD
0.0
-
(0.0)
0.0
(0.0)
5.2
55662
GrMEG Surmount
-
-
-
-
1.5
3.2
0.0
4.8
(3.2)
-100%
(0.0)
-100%
117
55663
Chard Substation
-
0.0
(0.0)
0.0
-
-
-
-
0.0
100%
(0.0)
-100%
118
55666
Halfway POD
-
0.4
0.4
0.0
-
-
-
-
0.4
100%
0.4
100%
119
55680
Hangingstone SAGD
5.4
15.7
21.1
(0.0)
24.8
30.9
-
(9.2)
-37%
(9.8)
-32%
120
55706
Edwards Lake Substation Connection
0.3
0.1
-
0.3
-
-
-
-
0.1
100%
-
121
55725
Saleski
4.0
0.3
-
4.3
12.2
11.9
24.1
-
(11.5)
-97%
122
55748
Dover West Clastics
-
-
-
-
1.8
28.7
-
30.5
(28.7)
-100%
123
55750
Dover West Leduc
0.3
0.3
-
0.5
1.8
8.4
0.0
10.2
(8.1)
-97%
(0.0)
-100%
0.1
7.8
(0.0)
-100%
55751
Dover North
0.0
6.1
-165024%
18.3
0%
-100%
116
124
13.1
0%
(24.1)
-
43898%
0%
-100%
0%
(0.1)
-
0.2
7.7
0.0
(7.8)
-101%
125
55797
Grand Rapids MacKay POD
-
1.9
-
1.9
-
-
-
-
1.9
100%
-
126
56015
Norberg Substation and 144kV Line
-
0.5
0.5
0.0
-
0.1
0.1
(0.0)
0.4
627%
0.4
566%
127
56055
Weasel Creek POD
-
0.2
0.2
0.0
-
-
-
-
0.2
100%
0.2
100%
128
56101
Vilna 777S Substation Contract Capacity Increase
-
0.0
-
129
56268
Primrose DTS Increase RAS - Phase 2
0.1
0.3
0.4
130
56352
Mahihkan 837S Substation 25 kV Breaker Addition
-
0.0
-
131
56360
Nabiye Generation Addition
0.2
0.2
0.4
132
56585
Taiga Substation and 144 kV Line
-
0.0
-
0.0
133
56642
La Corey Capacity Upgrade
0.6
7.3
7.9
0.0
134
56655
Alta Gas Kent - Generator - Central East
-
0.0
-
0.0
135
56660
Beartrap 144kV Line and New Substation
13.8
8.9
22.8
0.0
0%
0.0
-
-
-
-
0.0
100%
-
(0.0)
-
-
-
-
0.3
100%
0.4
0.0
-
-
-
-
0.0
100%
-
0.2
-
-
0.2
0.2
100%
0.4
6.5
7.1
-
13.7
(7.1)
-100%
-
-
-
-
7.3
100%
-
-
-
-
0.0
100%
-
-
-
-
-
8.9
100%
22.8
100%
-17%
(0.0)
7.9
0%
100%
0%
100%
0%
100%
0%
136
56665
Beartrap Cap Addition
0.9
2.8
3.7
0.0
1.2
3.3
4.5
-
(0.6)
-17%
(0.8)
137
56713
Irish Creek Capacity Upgrade
1.8
3.8
5.7
(0.0)
3.7
2.3
6.0
-
1.5
64%
(0.3)
138
56728
Lindbergh 25kV Bus Addition
0.5
1.8
2.3
(0.0)
0.6
0.2
0.8
0.0
1.6
950%
1.5
139
56810
Grizzly Bear Wind Facility Connection
0.1
0.7
-
0.9
-
-
-
-
0.7
100%
-
140
56865
Mainstream Wainwright
-
0.0
-
0.0
-
0.2
0.2
0.0
(0.2)
-87%
(0.2)
141
56893
Foster Creek Decommissioning
0.1
0.0
-
0.1
-
-
-
-
0.0
100%
-
142
56894
Foster Creek Cap Upgrade
0.1
0.2
0.3
0.0
-
-
-
-
0.2
100%
0.3
143
58180
Spirit River POD Substation
-
0.0
-
0.0
-
-
-
-
0.0
100%
-
144
58181
Simonette 733S Substation Capacity Upgrade
-
0.1
-
0.1
-
-
-
-
0.1
100%
-
145
58210
Halkirk Wind Power Interconnection
-
0.1
0.1
(0.0)
-
-
-
-
0.1
100%
0.1
146
58250
Sinclair Lake
-
0.0
-
0.0
-
-
-
-
0.0
100%
-
0%
147
58562
Hand Hills Wind Power Facility
0.8
(0.0)
-
0.7
1.5
4.6
-
6.1
(4.6)
-101%
-
0%
-6%
195%
0%
-100%
0%
100%
0%
0%
100%
SCHEDULE 4.2-T
Page 4 of 5
ATCO Electric Transmission (AET)
SUMMARY OF CAPITAL EXPENDITURES & ADDITIONS
FOR THE YEAR ENDED DECEMBER 31, 2014
($Millions)
2014 Actual
Line
No.
Project
148
58569
Hand Hills Wind Power Facility
0.4
0.0
-
149
58842
Wintering Hills Wind Farm Interconnection
-
0.1
0.1
150
58902
Monitor Substation Capacity Upgrade
0.5
2.1
151
58906
TransCanada Energy East EEPS5 (TransCanada Bindloss South Pumpstation)
-
0.1
152
58907
TransCanada Energy East EEPS3 (TransCanada Monitor Pumpstation)
-
153
58908
TransCanada Energy East EEPS4 (TransCanada Oyen Pumpstation)
154
58922
155
Description
CWIP
Balance
Cap
Expend
2014 Approved
Cap
Adds
CWIP
Balance
Cap
Expend
Cap
Adds
CWIP
Balance
Higher/(Lower)
Expenditures Actual
to Approved
Var.
%
Higher/(Lower)
Addition Actual
to Approved
Var.
%
0.2
0.8
-
1.0
(0.8)
-97%
-
(0.0)
-
-
-
-
0.1
100%
0.1
-
2.7
-
-
-
-
2.1
100%
-
0%
-
0.1
-
-
-
-
0.1
100%
-
0%
0.1
-
0.1
-
-
-
-
0.1
100%
-
0%
-
0.1
-
0.1
-
-
-
-
0.1
100%
-
0%
Eyre 558S Substation Interconnection
0.2
0.0
-
0.2
-
-
-
-
0.0
100%
-
0%
58923
Currant Lake Substation
3.6
0.2
-
3.8
3.4
-
-
3.4
0.2
100%
-
156
58924
Armitage Substation
4.1
0.2
0.1
4.3
3.5
-
-
3.5
0.2
100%
0.1
157
58925
Cavendish Substation
4.7
0.1
-
4.8
4.8
-
-
4.8
0.1
100%
-
0%
158
58965
Heartland Pump Station
0.1
0.5
-
0.6
-
-
-
-
0.5
100%
-
0%
159
58970
Bohn 913S Substation Transformer Addition
-
0.0
-
0.0
-
-
-
-
0.0
100%
-
0%
160
58971
Bauer 918S Substation Transformer Addition
-
0.1
-
0.1
-
-
-
-
0.1
100%
-
0%
161
58972
Beartrap 940S Substation Transformer Addition
162
TOTAL DIRECT ASSIGNED PROJECTS - CUSTOMER
-
0.0
0.5
CWIP
Balance
0%
100%
0%
100%
-
0.0
-
-
-
-
0.0
100%
-
0%
107.2
117.8
129.8
95.3
84.2
159.6
115.1
128.7
(41.8)
-26%
14.7
13%
1,260.3
1,098.4
418.7
1,940.1
1,119.0
827.1
393.8
1,552.2
271.4
33%
24.9
6%
163
164
TOTAL DIRECT ASSIGNED
165
166
TRANSMISSION ISOLATED GENERATION
167
90067
Rebuild Jasper Palisades Substation
0.3
168
90120
Distribution Isolated Generation Capital Maintenance
-
0.0
(0.1)
(0.1)
0.2
-
-
0.2
(0.0)
0.3
-
-
-
-
0.0
100%
(0.1)
-100%
(0.1)
-
0%
-100%
169
90130
Refurbish/Replace Engines and Turbines
0.4
1.7
0.5
1.6
-
1.0
1.0
-
0.8
81%
(0.4)
-43%
170
90136
CUL 43 Replacement
0.4
(0.4)
-
0.0
4.2
1.2
5.3
-
(1.6)
-132%
(5.3)
-100%
171
90134
Fort Chipewyan Capacity Increase
0.1
0.0
-
0.1
-
-
-
-
0.0
100%
-
172
90140
Transmission Isolated Operations Capital Maintenance
0.9
1.2
1.3
0.8
0.2
2.0
1.9
0.4
(0.9)
-43%
(0.6)
173
90150
Indian Cabins Capacity Increase
0.5
(0.1)
-
0.4
174
AUC Direction 21 - Contractor Inflation
175
0%
-33%
-
-
-
-
(0.1)
-100%
-
(0.0)
(0.0)
(0.1)
(0.0)
0.0
-100%
0.1
-100%
(1.8)
-44%
(6.4)
-79%
267.0
30%
(4.5)
-1%
2.6
2.3
1.7
3.2
4.5
4.2
8.2
0.5
1,319.1
1,163.7
475.6
2,007.1
1,159.1
896.6
480.2
1,575.6
0%
176
177
Total Transmission
178
Net Salvage
(24.2)
179
Additions to Property
451.4
(1.9)
478.3
180
181
DIRECT GENERAL PP&E
182
81000
Tools, Instruments and Equipment
1.2
6.3
7.2
0.3
-
2.7
2.7
-
3.5
130%
4.5
166%
183
82000
Office Furniture - Capital Division
-
0.6
0.6
0.0
-
0.9
0.9
-
(0.3)
-37%
(0.3)
-37%
184
84000
Transportation Equipment
0.6
10.7
10.2
1.1
-
8.5
8.5
-
2.2
26%
1.7
20%
1.8
17.6
18.0
1.4
-
12.2
12.2
-
5.4
45%
5.9
48%
185
186
SOFTWARE
187
82407
Asset Management
-
-
-
-
-
0.5
0.5
-
(0.5)
-100%
(0.5)
-100%
188
82416
Maximo Enhancements
-
-
-
-
0.1
0.1
0.1
0.1
(0.1)
-100%
(0.1)
-100%
189
82417
Maximo/Oracle Integration
-
-
-
-
-
0.1
0.1
-
(0.1)
-100%
(0.1)
-100%
190
82418
Project Management Improvements
-
-
-
-
0.1
0.3
0.3
0.1
(0.3)
-100%
(0.3)
-100%
191
82419
Records Management
-
-
-
-
0.1
0.2
0.2
0.1
(0.2)
-100%
(0.2)
-100%
192
82424
Oracle eBusiness Upgrade
1.2
(1.1)
0.1
0.0
-
-
-
-
(1.1)
-100%
0.1
100%
193
82446
Technology Enhancements
-
-
-
-
-
0.1
0.1
-
(0.1)
-100%
(0.1)
-100%
194
82452
Windows 7 Upgrade
-
0.2
0.2
(0.0)
0.0
-
-
0.0
0.2
100%
0.2
100%
195
82501
MOPS Phase II
-
0.7
0.7
0.0
-
-
-
-
0.7
100%
0.7
100%
-
2.3
2.2
0.1
2.8
4.5
4.5
2.8
(2.2)
-49%
(2.3)
-51%
196
82502/8253 Cyber Security Program
SCHEDULE 4.2-T
Page 5 of 5
ATCO Electric Transmission (AET)
SUMMARY OF CAPITAL EXPENDITURES & ADDITIONS
FOR THE YEAR ENDED DECEMBER 31, 2014
($Millions)
2014 Actual
Cap
Expend
Cap
Adds
CWIP
Balance
CWIP
Balance
Cap
Expend
Cap
Adds
CWIP
Balance
Higher/(Lower)
Expenditures Actual
to Approved
Var.
%
Higher/(Lower)
Addition Actual
to Approved
Var.
%
Line
No.
Project
197
82508
Meter Attributes and Readings Management System (MARMS) Phase 3
-
-
-
-
-
0.4
0.4
-
(0.4)
-100%
(0.4)
-100%
198
82525
Intelex
-
0.4
0.4
(0.0)
-
-
-
-
0.4
100%
0.4
100%
199
82531
Phase 1 of MOPS Gap
-
0.1
0.1
(0.0)
-
-
-
-
0.1
100%
0.1
100%
200
82533
MOPS Gap Phase II - Oracle Integration
-
0.0
-
0.0
-
-
-
-
0.0
100%
-
201
82582
Enterprise Technology Innovation
-
0.1
0.1
0.0
-
-
-
-
0.1
100%
0.1
202
82585
Infrastructure Resilience and Advancement Fund
-
0.0
-
0.0
-
-
-
-
0.0
100%
-
203
82586
ATCO Performance Functional Lifecycle
-
0.1
0.1
0.0
-
-
-
-
0.1
100%
0.1
204
82588
Microsoft Software Assurance
-
0.1
0.1
0.0
-
-
-
-
0.1
100%
0.1
100%
205
82592
Maximo Enhancement - Workforce Mobility
-
0.5
0.5
(0.0)
-
-
-
-
0.5
100%
0.5
100%
206
82594
Software - IPS
-
0.3
0.3
0.0
-
-
-
-
0.3
100%
0.3
100%
207
82595
Electronic Tender & Contract Formation System (SciQuest)
-
0.0
-
0.0
-
-
-
-
0.0
100%
-
208
82597
Oracle R12 Upgrade
-
1.8
1.8
(0.0)
-
-
-
-
1.8
100%
1.8
100%
Description
CWIP
Balance
2014 Approved
0%
100%
0%
100%
0%
209
82611
Oracle Enhancements
-
0.0
0.0
0.0
-
-
-
-
0.0
100%
0.0
100%
210
82613
Hyperion Enhancements for T
-
0.9
0.9
(0.0)
-
-
-
-
0.9
100%
0.9
100%
211
82614
2013 Miscellaneous Maximo & MOPS Enhancements
-
0.0
0.0
0.0
-
-
-
-
0.0
100%
0.0
100%
212
82620
Oracle R12 Upgrade Transmission Specific
-
0.1
0.1
0.0
-
-
-
-
0.1
100%
0.1
100%
213
82631
Oracle HR Functional Lifecycle
-
0.0
-
0.0
-
-
-
-
0.0
100%
-
0%
214
82639
Business Intelligence & Metrics Reporting Improvements
-
0.0
-
0.0
-
-
-
-
0.0
100%
-
0%
-
215
82645
OFIN Licenses True Up
-
0.0
-
-
-
-
0.0
100%
216
82649
Company 21 Re-organization
-
1.3
1.3
(0.0)
-
-
-
-
1.3
100%
1.3
217
82651
GIS Strategic Implementation - Phase 1
-
0.3
-
0.3
-
-
-
-
0.3
100%
-
1.2
8.2
8.9
0.6
3.1
6.3
6.3
3.1
1.9
30%
2.5
218
219
-
0.0
0%
100%
0%
40%
BUILDINGS
220
85000
Land, Buildings and Structures
0.8
6.6
5.1
2.4
0.2
2.7
2.7
0.2
4.0
147%
2.4
90%
221
85030
Nisku Fabrication Building
-
1.8
1.8
0.0
6.7
-
-
6.7
1.8
100%
1.8
100%
-100%
(3.7)
-100%
222
85816
Drumheller Service Building - Administration Phase I
0.3
-
-
0.3
3.0
0.6
3.7
0.0
(0.6)
223
85820
Peace River Service Building Addition
0.1
-
-
0.1
0.0
-
-
0.0
-
0%
-
224
85841
Asset Disposition
0.1
-
-
0.1
0.3
-
-
0.3
-
0%
-
225
85829
High Level Service Building
0.1
-
-
0.1
1.9
1.5
3.4
0.0
(1.5)
1.4
8.5
6.9
2.9
12.2
4.8
9.7
7.3
3.7
226
227
228
AUC Direction 21 - Contractor Inflation
-
(0.3)
(0.3)
229
AUC Direction 5 - Allocation of Non DA Capital VPP (IR AUC-AE-10)
-
0.7
0.7
-
15.3
23.8
28.6
10.5
230
4.4
231
Net Salvage
232
Additions to Property
233
Allocated General PP&E
34.3
33.8
4.9
0.1
(0.2)
33.9
28.4
-
1.1
0.0
234
235
Total Transmission Capital Additions
1,323.5
1,197.9
485.3
2,012.0
1,174.5
920.4
507.8
1,586.0
0%
0%
-100%
(3.4)
-100%
76%
(2.8)
-29%
SCHEDULE 4.2-T
CONTRIBUTIONS
Page 1 of 2
ATCO Electric Transmission (AET)
SUMMARY OF CAPITAL CONTRIBUTIONS
FOR THE YEAR ENDED DECEMBER 31, 2014
($Millions)
2014 Actual
Line
No. Project
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
49
50
51
52
53
54
55
Description
DIRECT ASSIGNED PROJECTS
51074 Fort Nelson Remedial Action Scheme
51162 Blumenort - Windy Hills 144kV Transmission Line
51168 Norcen Substation Capacity
51181 Carmon Creek Cogen
51184 Swan Hills Synfuel Generation Interconnection
51341 Buchanan Creek Substation
51440 Whitetail Peaking Station Interconnection
51680 Brintnell Permanent Capacity Addition
52025 Slave Lake Pulp Biomethanation
52045 Muskwa Gas to Power Facility
53032 Ksituan River Voltage Regulator & 25 kV Breaker Addition
53720 Edith Lake Transformer Addition
53721 Swan River Transformer Replacement
54381 Mercer Hill Breaker Addition
55147 9L66/9L32 Line Relocation
55187 Service for MacKay SAGD
55230 Service for Ivanhoe SAGD
55255 Relocation of Joslyn Substation 849S
55325 Sweetheart Lake (Algar Expansion)
55340 Dog Rib POD
55579 Secord Substation
55584 Green Stocking Substation
55619 Cheecham Kinosis Breaker Addition
55622 Cheecham POD
55631 Quigley 144kV Line and Substation
55632 Surmount II (Stage 2)
55633 Surmount II (Stage 3)
55655 Bohn POD
55666 Halfway POD
55680 Hangingstone SAGD
55725 Saleski
55748 Dover West Clastics
55751 Dover North
56015 Norberg Substation and 144kV Line
56052 Abee Substation
56055 Weasel Creek POD
56268 Primrose DTS Increase RAS - Phase 2
56360 Nabiye Generation Addition
56585 Taiga Substation and 144 kV Line
56642 La Corey Capacity Upgrade
56655 Alta Gas Kent - Generator - Central East
56660 Beartrap 144kV Line and New Substation
56665 Beartrap Cap Addition
56713 Irish Creek Capacity Upgrade
56725 Lindbergh 144kV Line and Substation
56775 Bauer 144 kV Line and Substation
56810 Grizzly Bear Wind Facility Connection
56865 Mainstream Wainwright
56894 Foster Creek Cap Upgrade
58922 Eyre 558S Substation Interconnection
58925 Cavendish Substation
58210 Halkirk Wind Power Interconnection
58250 Sinclair Lake
58562 Hand Hills Wind Power Facility
CrossReference
CWIP
Balance
0.1
1.3
1.6
0.4
0.2
0.1
2.0
0.3
20.6
21.0
15.0
0.2
0.2
22.3
1.3
0.1
0.1
1.0
-
Cap
Expend
0.1
0.1
3.4
10.9
5.4
0.1
(1.5)
0.1
0.2
(0.3)
(0.1)
0.9
(2.0)
15.6
(0.3)
3.6
0.7
5.4
1.8
(0.5)
8.6
0.1
0.7
14.6
(8.7)
0.7
6.5
(1.5)
0.9
(3.0)
0.2
0.2
2.7
0.1
(6.1)
1.5
4.1
(1.0)
(1.3)
0.5
0.2
0.5
0.3
0.7
Cap
Adds
7.0
(1.5)
0.2
0.2
(0.3)
(0.1)
0.7
1.8
(0.5)
0.1
21.3
12.3
0.7
21.5
(1.5)
0.9
(3.0)
0.4
0.4
2.7
16.2
1.5
4.1
(1.0)
(1.3)
0.3
0.5
-
2014 Approved
CWIP
Balance
CWIP
Balance
Cap
Expend
0.2
1.4
3.4
10.9
0.0
0.5
0.0
0.2
0.9
15.6
0.1
3.6
5.4
8.6
0.0
14.6
0.0
(0.0)
0.0
0.1
0.0
0.0
1.8
0.0
0.1
1.0
(0.0)
0.3
0.7
0.4
3.3
3.5
2.6
1.7
1.5
1.6
0.2
6.5
17.8
10.0
5.3
15.0
5.2
2.7
1.5
10.8
3.1
0.1
1.0
-
2.0
2.9
7.8
9.8
10.7
2.6
11.9
4.4
5.0
1.1
1.8
0.2
0.7
6.1
Cap
Adds
5.3
3.5
4.5
7.8
12.7
25.7
2.6
1.1
1.8
0.2
0.1
1.6
-
CWIP
Balance
0.4
2.6
1.7
1.5
0.2
6.5
17.8
(2.9)
10.0
5.3
11.9
4.4
5.2
2.7
1.5
5.0
10.8
3.1
0.1
6.1
Higher/(Lower)
Expenditures Actual
to Approved
0.1
0.1
3.4
10.9
(2.0)
5.4
0.1
(1.5)
0.1
0.2
(0.3)
(0.1)
0.9
(2.0)
12.7
(0.3)
3.6
0.7
5.4
1.8
(0.5)
0.8
0.1
0.7
4.8
(8.7)
0.7
(4.2)
(2.6)
(11.9)
(4.4)
(1.5)
0.9
(3.0)
0.2
0.2
(5.0)
2.7
0.1
(6.1)
0.4
2.3
(1.0)
(1.3)
0.5
(0.2)
0.2
(0.7)
0.5
0.3
(5.4)
Var.
%
100%
100%
100%
100%
-100%
100%
100%
-100%
100%
100%
-100%
-100%
100%
-100%
439%
-100%
100%
100%
100%
100%
-100%
10%
100%
100%
49%
-100%
100%
-39%
-100%
-100%
-100%
-100%
100%
-100%
100%
100%
-100%
100%
100%
-100%
38%
127%
-100%
-100%
100%
-100%
100%
-100%
100%
100%
-88%
Higher/(Lower)
Addition Actual
to Approved
(5.3)
3.5
(1.5)
0.2
0.2
(0.3)
(0.1)
(4.5)
0.7
1.8
(0.5)
(7.8)
0.1
21.3
(12.7)
12.3
0.7
(4.2)
(2.6)
(1.5)
0.9
(3.0)
0.4
0.4
2.7
16.2
0.4
2.3
(1.0)
(1.3)
(0.2)
0.3
(0.1)
(1.6)
0.5
-
Var.
%
-100%
99%
-100%
100%
100%
-100%
-100%
-100%
100%
100%
-100%
-100%
100%
100%
-100%
100%
100%
-16%
-100%
-100%
100%
-100%
100%
100%
100%
100%
38%
127%
-100%
-100%
-100%
100%
-100%
-100%
100%
-
SCHEDULE 4.2-T
CONTRIBUTIONS
Page 2 of 2
ATCO Electric Transmission (AET)
SUMMARY OF CAPITAL CONTRIBUTIONS
FOR THE YEAR ENDED DECEMBER 31, 2014
($Millions)
2014 Actual
Line
No. Project
56
57
58
59
60
61
62
63
64
65
58569
58902
Description
Hand Hills Wind Power Facility
Monitor Substation Capacity Upgrade
OTHER TRANSMISSION
50020 Transmission Capital Maintenance - Lines
50060 Substation Rebuilds
50010 Transmission Capital Maintenance - Substations
CrossReference
CWIP
Balance
Cap
Expend
Cap
Adds
87.8
0.5
3.0
68.8
83.7
20.0
20.0
2.8
1.4
4.2
107.8
73.0
2014 Approved
CWIP
Balance
Cap
Adds
CWIP
Balance
Higher/(Lower)
Expenditures Actual
to Approved
CWIP
Balance
Cap
Expend
Var.
%
0.5
3.0
72.9
93.8
1.0
68.0
66.9
1.0
94.9
(0.5)
3.0
-51%
100%
2.0
0.6
2.6
20.8
0.8
21.6
-
10.3
2.5
12.8
10.3
2.5
12.8
-
(7.5)
(2.5)
1.4
-73%
-100%
100%
86.3
94.5
93.8
80.8
79.7
94.9
Higher/(Lower)
Addition Actual
to Approved
-
(8.3)
(2.5)
0.6
Var.
%
-
-80%
-100%
100%
SCHEDULE 4.3-T
EXPENDITURES
Page 1 of 3
ATCO Electric Transmission (AET)
VARIANCE EXPLANATIONS OF CAPITAL EXPENDITURES
FOR THE YEAR ENDED DECEMBER 31, 2014
($Millions)
Line
No. Project
Description
2014
2014
Variance
Actual Approved Actual to
Expend Expend Approved
1
2
CAPITAL MAINTENANCE
50010 Transmission Capital Maintenance - Substations
10.9
7.1
3
50020 Transmission Capital Maintenance - Lines
17.3
4
50040 Transmission System Right-of-Way
1.3
5
50041 Transmission Rights-of-Way Widening
6
Var
%
Variance Explanation
3.8
54%
7.9
9.4
119%
Actual expenditures were higher than forecast mainly due to unanticipated customer requested transmission line relocation projects.
3.3
(2.1)
-62%
Actual expenditures were lower than forecast mainly due to the deferral of a portion of the first time herbicide application program to future years in order to
maximize the effectiveness of the application. This was necessary because the actual vegetation growth was lower than anticipated at the time of the 2013-14 GTA
submission.
3.4
5.7
(2.3)
-41%
Actual expenditures were lower than forecast mainly due to delays caused by weather. Ground conditions were not favorable to execute the 9L56 widening project. This was partially offset by widening work undertaken on 7L40 to address high priority right of way width issues and coordinate widening efforts with other
Vegetation Management work scheduled, and higher than forecast Vegetation Management activities required to manage fire risk around facilities (substations and
telecommunication towers).
50060 Substation Rebuilds
9.4
12.9
(3.5)
-27%
Actual expenditures were lower than forecast mainly due to project schedules. Firstly, the Steepbank substation rebuild project was put on-hold due to lack of
customer commitment. Secondly, the schedule of the Vegreville substation rebuild project was adjusted to enable coordination with direct assigned projects. Thirdly,
the project schedules for the Keg River and Muskeg River substation rebuild projects were adjusted to allow enough time to explore other cost effective solutions.
These expenditure reductions were partially offset by increased expenditures on the Swan River substation rebuild and Battle River substation rebuild projects. The
project schedule for the Swan River rebuild project was adjusted in previous years to accommodate coordination with a direct assigned project. In addition, the cost
of the Swan River project was higher than the preliminary forecast estimate due to market conditions and higher than expected tender results. Also, the schedule of
the Battle River project was adjusted in previous years in order to ensure that the outage requirements coincided with the Battle River plant shut downs.
7
50170 Transmission Emergency Apparatus
0.4
2.2
(1.8)
-82%
Actual expenditures were lower than forecast mainly due to a delay of receipt of equipment. These emergency apparatus are scheduled to be received in 2015.
8
50190 Transmission Line Ground Clearance
0.5
4.3
(3.9)
-89%
Actual expenditures were lower than forecast. The Line-Ground Clearance mitigation program is being executed in coordination with the Double Circuit mitigation
program to ensure efficient project execution. Both programs were placed on hold to facilitate a review of project requirements and priorities in concert with the
AESO.
9
50500 840S McNeill HVDC Control Replacement - Phase 1
1.4
-
1.4
100%
10
50960 Mitigate Equipment Problems
0.7
1.7
(1.0)
-59%
Actual expenditures were higher than forecast due to project schedule adjustments so as to allow enough time to resolve product quality issues, which arose during
the engineering and construction phase of the project. This project, forecast in the 2013-2014 GTA to be complete in 2013 is now scheduled to be completed in
Actual expenditures were lower than forecast due to a combination of weather related delays and work management. Ground conditions were not favorable at the
time work was scheduled in the 2013 - 2014 GTA application to remove PCB contaminated equipment. In addition, projects schedules were adjusted to manage
resources effectively. Projects and programs were reviewed and lower priority projects delayed. This enabled AET to better use internal engineering and
construction resources and enabled project work to be bundled for execution in future years.
11
12
TELECOMMUNICATION
50400 Telecommunication Capital Maintenance
4.2
1.2
3.1
259%
Actual expenditures were higher than forecast mainly due to an increase in scope beyond what was anticipated in the 2013-2014 GTA for a telecommunication
tower corrosion management program. Corrosion issues required inspections and corrosion mitigation beyond that contemplated in the forecast.
13
59911 Telecom Site Power Backup
1.2
5.0
(3.8)
-76%
14
59943 Grande Prairie Area Telecom Reliability
0.0
1.2
(1.1)
-97%
Actual expenditures were lower than forecast due to a portion of the scope being deferred to future years based on the outcome of the AESO's black start path
studies.
Actual expenditures were lower than forecast due to a project schedule adjustment to allow time to explore other cost-effective solutions. Tower estimates received
during the preliminary design were significantly higher than anticipated. The timing of this project was also adjusted to coordinate with the network multiplexer
upgrade project (59955). This coordination minimizes rework by ensuring the project design incorporates the new multiplexer platforms rather than obsolete
multiplexers.
15
16
DIRECT ASSIGNED PROJECTS SYSTEM
58001 Edmonton-Calgary 500 kV East Route
737.0
417.1
319.9
77%
17
18
58005 Southeast Bulk System Reinforcement
53320 High Prairie to Triangle 144kV Line Upgrade
23.1
37.1
18.7
25.5
4.4
11.6
24%
45%
19
55125 Birchwood 240kV Line and Substation
20.8
60.5
(39.7)
-66%
Actual expenditures were higher than forecast due to a combination of reasons. Firstly, actual costs were higher than forecast costs for substation ground grid
refurbishment projects. Ground Grid studies completed subsequent to the 2013-14 GTA submission showed more than forecast ground grid deficiencies that
needed to be addressed to manage safety risks. Secondly, a project that was unforeseen at the time of the 2013-2014 GTA submission was required to change
meters in order to maintain compatibility with modifications to the cellular network and to continue to meet regulatory requirements. Finally, additional scope was
required to address protection coordination risks due to system growth.
Expenditures higher due mainly to the AUC directed reductions to AET's forecasts that were not, in fact, realized, as well as higher line construction tender prices
and increased Right of Way costs.
Expenditures higher due mainly to the AUC directed reductions to AET's forecasts that were not, in fact, realized.
Expenditures were higher than forecast due mainly to work being delayed from 2013 to 2014 as a result of additional time being required to prepare the Proposal to
Provide Services (PPS) estimate.
Expenditures were lower than forecast due mainly to the re-allocation of the 9L95 line work into a separate appropriation 55127. The 2013/14 General Tariff
Application (GTA) assumed all costs would be included within appropriation 55125.
SCHEDULE 4.3-T
EXPENDITURES
Page 2 of 3
ATCO Electric Transmission (AET)
VARIANCE EXPLANATIONS OF CAPITAL EXPENDITURES
FOR THE YEAR ENDED DECEMBER 31, 2014
($Millions)
Line
No. Project
Description
2014
2014
Variance
Actual Approved Actual to
Expend Expend Approved
Var
%
Variance Explanation
Expenditures were lower than forecast due mainly to work being deferred to a later period due to consultations with the AESO which resulted in the PPS being
submitted in December of 2014.
Expenditures were lower than forecast due to materials being transferred to other projects after this project was deferred at the request of the AESO.
Expenditures were lower than forecast due mainly to construction moving from 2014 to a future period due to additional time being required to finalize the substation
location and 240 kV line route.
Expenditures are higher than forecast due mainly to trailing costs for line materials related to prior year capitalizations.
Expenditures were higher than forecast due to substation and line modifications being more extensive than estimated. In addition the AUC directed reductions to
AET's forecasts were not, in fact, realized.
Expenditures were lower than forecast due mainly to ISD being deferred as the AESO reviewed the project needs and functional specifications.
Expenditures were higher than forecast mainly due to the ISD being delayed from 2013 to 2014 as a result of upgrading the access road to the Kettle River
substation from a winter road to an all season road to provide year round access.
Expenditures were higher than forecast due mainly to construction work for Marguerite Lake Substation and line 7L587 which was deferred to 2014 from 2013.
Expenditures were lower than forecast as the project requirements were being reviewed by the AESO; the system work in this area is planned to be incorporated
into the Vermillion - Red Deer and Edgerton- Provost Transmission Development (VREPTD) program.
Expenditures were higher than forecast due mainly to AESO putting the project on hold until Q3 2013 which resulted in delaying the work from 2013 to 2014.
Expenditures were lower than forecast due to the AESO's notification that the project may be cancelled.
20
55126 Ells – 9L76/9L08 240kV D/C Line
3.6
41.9
(38.3)
-91%
21
22
55127 9L95 Development
55322 Algar Area System Reinforcement
(3.0)
20.6
22.8
(3.0)
(2.2)
-100%
-10%
23
24
55585 North Fort McMurray Transmission Development
55703 Heart Lake Station Expansion
2.9
10.9
3.4
2.9
7.5
100%
219%
25
26
55737 Thickwood Development
55785 Kettle River Substation and 240kV Line Tap
0.7
12.4
1.9
-
(1.2)
12.4
-64%
100%
27
28
56539 Cold Lake Development
57102 7L50 Rebuild
3.1
-
(0.0)
22.0
3.1
(22.0)
100%
-100%
29
30
31
32
57121
57130
57151
57155
1.1
0.0
1.9
65.9
5.7
40.0
1.1
(5.7)
1.9
25.9
100%
-100%
100%
65%
33
57156 Kitscoty Area Development
13.3
-
13.3
100%
34
57157 St. Paul Substation and Line
26.6
8.0
18.6
233%
35
36
37
38
39
40
41
51181
51184
51425
54381
55010
55147
8.6
(0.0)
(0.0)
1.0
(0.3)
2.0
3.9
3.1
4.4
8.6
(2.0)
(3.9)
1.0
(3.1)
(4.7)
100%
-100%
-100%
100%
-100%
-107%
42
55187 Service for MacKay SAGD
9.7
2.8
6.8
239%
43
44
45
46
55250
55325
55579
55632
(0.0)
7.1
5.7
3.0
10.8
5.3
-
(10.8)
1.8
5.7
3.0
-100%
33%
100%
100%
47
55633 Surmount II (Stage 3)
17.0
9.8
7.2
74%
48
49
55651 Egg Lake Substation and 144kv Line
55655 Bohn POD
(0.9)
5.2
4.5
(0.0)
(5.4)
5.2
-119%
100%
50
51
52
53
54
55662
55680
55725
55748
55750
GrMEG Surmount
Hangingstone SAGD
Saleski
Dover West Clastics
Dover West Leduc
15.7
0.3
0.3
3.2
24.8
11.9
28.7
8.4
(3.2)
(9.2)
(11.5)
(28.7)
(8.1)
-100%
-37%
-97%
-100%
-97%
55
56
57
58
59
55751
55797
56585
56642
56660
Dover North
Grand Rapids MacKay POD
Taiga Substation and 144 kV Line
La Corey Capacity Upgrade
Beartrap 144kV Line and New Substation
(0.1)
1.9
0.0
7.3
8.9
7.7
7.1
-
(7.8)
1.9
(7.1)
7.3
8.9
-101%
100%
-100%
100%
100%
7L14 - Central East Clearance Mitigation
Athabasca Area Transmission Development
St. Paul Area – Watt Lake and Whitby Lake Substations
Cold Lake Area - Bourque-Bonnyville
DIRECT ASSIGNED PROJECTS - CUSTOMER
Carmon Creek Cogen
Swan Hills Synfuel Generation Interconnection
Harmon Valley POD
Mercer Hill Breaker Addition
Commercial Plant
9L66/9L32 Line Relocation
Joslyn North Mine 240 kV Connection
Sweetheart Lake (Algar Expansion)
Secord Substation
Surmount II (Stage 2)
Expenditures were higher than forecast due mainly to Whitby Lake substation construction being deferred from 2013 to 2014.
Expenditures were higher than forecast due mainly to higher construction tender prices, higher brushing, access and landowner costs and the AUC directed
reductions to AET's forecasts that were not, in fact, realized.
Expenditures were higher than forecast due mainly to a delay in construction from 2013 to 2014 due to the schedule complexities related to equipment from other
projects.
Expenditures were higher than forecast due mainly to higher cost of line and substation construction as well as higher land costs. In addition, costs were deferred to
2014 from 2013 due to Surface Rights Board hearing and the estimate being re-baselined.
Expenditures were higher than forecast as this customer project was not anticipated at the time of the 2013/14 GTA.
Expenditures were lower than forecast due to the cancellation of the project at the customer's request.
Expenditures were lower than forecast due to the cancellation of the project at the customer's request.
Expenditures were higher than forecast as this customer project was not anticipated at the time of the 2013/14 GTA.
Expenditures were lower due to the forecasted customer project not proceeding.
Expenditures were lower than forecast due to the project being deferred to align with the customer's schedule; in addition the actual costs incurred were transferred
to Transmission Capital Maintenance, appropriation 50020 as this customer line relocation project is not direct assigned by the AESO.
Expenditures were higher than forecast due mainly to the 2014 Approved Expenditures being based on the OOM estimate - Option1 whereas the actual scope
included a longer line and additional substation; increasing project costs.
Expenditures were lower than forecast due to the cancellation of the project at the customer's request.
Expenditures were higher than forecast due to work from 2013 being delayed to 2014 as a result of additional time being required to prepare the PPS.
Expenditures were higher than forecast as this customer project was not anticipated at the time of the 2013/14 GTA.
Expenditures were higher than forecast due to a delay in ISD from 2013 to 2014 to align with customer's schedule, resulting in construction being completed in
2014.
Expenditures were higher than forecast due mainly to higher project costs than was forecasted in the 2013/14 GTA, the AUC directed reductions to AET's forecasts
were not, in fact, realized, as well as work deferred from 2013 being completed in 2014.
Expenditures were lower than forecast due to the cancellation of the project at the customer's request.
Expenditures were higher than forecast due to a project delay as a result of the AESO requiring additional time to review the PPS and NID estimates, shifting project
construction to 2014 from 2013 as planned.
Expenditures were lower than forecast due to the cancellation of the project at the customer's request.
Expenditures were lower than forecast due mainly to lower construction costs associated with substation design changes as well as release of contingency.
Expenditures were lower than forecast due mainly to the project being deferred at the customer's request.
Expenditures were lower than forecast due to the cancellation of the project at the customer's request.
Expenditures were lower than forecast mainly due to the AESO's review of the NID, resulting in the delay of the PPS submission and Facility Application and in 2014
the customer requested a further delay in the project so that the ISD shifts to 2017.
Expenditures were lower than forecast due to the cancellation of the project at the customer's request.
Expenditures were higher than forecast as this customer project was not anticipated at the time of the 2013/14 GTA.
Expenditures were lower than forecast due to the cancellation of the project at the customer's request.
Expenditures were higher than forecast as this customer project was not anticipated at the time of the 2013/14 GTA.
Expenditures were higher than forecast due mainly to a delay in receiving permit and license (P&L) due to an AUC hearing regarding the line route, as well as a
restricted construction time frame as the area was environmentally sensitive, which resulted in line and substation construction being done in 2014 instead of 2013.
SCHEDULE 4.3-T
EXPENDITURES
Page 3 of 3
ATCO Electric Transmission (AET)
VARIANCE EXPLANATIONS OF CAPITAL EXPENDITURES
FOR THE YEAR ENDED DECEMBER 31, 2014
($Millions)
Line
No. Project
Description
2014
2014
Variance
Actual Approved Actual to
Expend Expend Approved
Var
%
Variance Explanation
3.8
1.8
2.3
0.2
1.5
1.6
64%
950%
Expenditures were higher due mainly to work being deferred to 2014 from 2013.
Expenditures were higher than forecast due mainly to the GTA estimate being based on the Order of Magnitude (OOM) estimate which was lower than the PPS that
was submitted at a later date, as the OOM did not include substation expansion and access road. Additionally, the AUC directed reductions to AET's forecasts were
not, in fact, realized.
58562 Hand Hills Wind Power Facility
58902 Monitor Substation Capacity Upgrade
TRANSMISSION ISOLATED GENERATION
90136 CUL 43 Replacement
DIRECT GENERAL PP&E
81000 Tools and Equipment
(0.0)
2.1
4.6
-
(4.6)
2.1
-101%
100%
Expenditures were lower than forecast due to the Facility Application being delayed while the AUC reviewed system access issues.
Expenditures were higher than forecast as this customer project was not anticipated at the time of the 2013/14 GTA.
(0.4)
1.2
(1.6)
-132%
Actual expenditures were lower than forecast because the project is currently on-hold to evaluate the transmission strategy for Jasper.
6.3
2.7
3.6
100%
84000 Transportation Equipment
SOFTWARE
82424 Oracle eBusiness Upgrade
10.7
8.5
2.2
26%
Expenditures were higher than forecast due mainly to the Transmission Asset Management project which was required to create an asset management framework
that meets international standard ISO55001 requirements.
Higher mainly due to the delay of some equipment forecasted to be purchased in 2013 that was subsequently purchased in 2014.
(1.1)
-
(1.1)
-100%
71 82502/ Cyber Security Program
82532
72 82597 Oracle R12 Upgrade
2.3
4.5
(2.2)
-49%
1.8
-
1.8
100%
73
82649 AET Accounting System
1.3
-
1.3
100%
74
75
BUILDINGS
85000 Land, Buildings and Structures
6.6
2.7
4.0
147%
76
77
85030 Nisku Panel Shop
85829 High Level Service Building
1.8
-
1.5
1.8
(1.5)
100%
-100%
60
61
56713 Irish Creek Capacity Upgrade
56728 Lindbergh 25kV Bus Addition
62
63
64
65
66
67
68
69
70
The 2013 ending WIP balance reflects that Transmission was assumed to own 50% of this Appropriation however in the subsequent T/D split 100% of this project
was transferred to ATCO Electric Distribution.
Expenditures lower due to cost savings related to a downgrade in the test lab for the Physical Security Project, quicker execution on the Change and Configuration
Management Project and the automation of Maximo classification to cyber assets on the BES Asset Classification Project.
The version of Oracle that was previously used went unsupported in late 2014 as such a project was initiated in 2013 to upgrade to a new supported version. The
project was complete in 2014.
In 2013, a need was identified for the Transmission Division to report and function as a stand alone division. To accomplish this, a separate set of books in Oracle
was implemented for January 1, 2014 which is now supporting the management of the Transmission assets of the company.
Expenditures were higher mainly due to a Vegreville expansion and renovations to Standard Life Building (2nd floor) and ATCO Centre Building (4th floor) to
accommodate employee growth.
Expenditures were higher mainly due to construction of a material storage building for the Panel Shop in Nisku.
Expenditures were lower than forecast mainly due to a re-evaluation of requirements and alternatives.
SCHEDULE 4.3-T
ADDITIONS
Page 1 of 3
ATCO Electric Transmission (AET)
VARIANCE EXPLANATIONS OF CAPITAL ADDITIONS
FOR THE YEAR ENDED DECEMBER 31, 2014
($Millions)
Line
No. Project
Description
2014
2014
Variance
Actual Approved Actual to
Adds
Adds
Approved
Var
%
Variance Explanation
1
2
CAPITAL MAINTENANCE
50010 Transmission Capital Maintenance - Substations
4.1
6.7
(2.6)
-39% Actual additions were lower than forecast mainly because projects schedules were adjusted to manage resources effectively. After the 2013-14 GTA
submission, the program was reviewed and lower priority projects delayed. This was necessary to enable AET to better use internal engineering and
construction resources and enabled project work to be bundled for execution in future years.
3
50020 Transmission Capital Maintenance - Lines
3.8
14.4
(10.6)
-74% Actual additions were lower than forecast due to delays with executing transmission line relocation projects in accordance with customer schedules.
These transmission line relocation projects are scheduled to be completed in future years.
4
50040 Transmission System Right-of-Way
1.2
3.3
(2.2)
-65% Actual additions were lower than forecast mainly due to the deferral of a portion of the first time herbicide application program to future years in order
to maximize the effectiveness of the application. This was necessary because the actual vegetation growth was lower than anticipated at the time of
the 2013-14 GTA submission.
5
50060 Substation Rebuilds
10.9
18.7
(7.7)
-41% Actual additions were lower than forecast mainly due to project schedules. Firstly, the Steepbank substation rebuild project was put on-hold due to
lack of customer commitment. Secondly, the schedule of the Vegreville substation rebuild project was adjusted to enable coordination with direct
assigned projects. Thirdly, the project schedules for the Keg River and Muskeg River substation rebuild projects were adjusted to allow enough time to
explore other cost effective solutions. These expenditure reductions were partially offset by increased expenditures on the Swan River substation
rebuild and Battle River substation rebuild projects. The project schedule for the Swan River rebuild project was adjusted in previous years to
accommodate coordination with a direct assigned project. In addition, the cost of the Swan River project was higher than the preliminary forecast
estimate due to market conditions and higher than expected tender results. Also, the schedule of the Battle River project was adjusted in previous
years in order to ensure that the outage requirements coincided with the Battle River plant shut downs.
6
50130 Replace or Rebuild Major Transmission Apparatus
3.4
4.4
(1.0)
-22% Actual additions were lower than forecast mainly because of a delay with the receipt of materials. In addition, projects schedules were adjusted to
manage resources effectively. After the 2013-14 GTA submission, the program was reviewed and lower priority projects delayed. This was necessary
to enable AET to better use internal engineering and construction resources and enabled project work to be bundled for execution in future years.
7
50190 Transmission Line Ground Clearance
0.6
4.3
(3.8)
-87% Actual additions were lower than forecast. The Line-Ground Clearance mitigation program is being executed in coordination with the Double Circuit
mitigation program to ensure efficient project execution. Both programs were placed on hold to facilitate a review of project requirements and
priorities in concert with the AESO.
8
50960 Mitigate Equipment Problems
0.2
1.7
(1.5)
-89% Actual additions were lower than forecast due to a combination of weather related delays and work management. Ground conditions were not
favorable at the time work was scheduled in the 2013 - 2014 GTA application to remove PCB contaminated equipment. In addition, projects
schedules were adjusted to manage resources effectively. Projects and programs were reviewed and lower priority projects delayed. This enabled
AET to better use internal engineering and construction resources and enabled project work to be bundled for execution in future years.
9
10
TELECOMMUNICATION
50400 Telecommunication Capital Maintenance
7.6
0.6
7.0 1083% Actual additions were higher than forecast mainly due to an increase in scope beyond what was anticipated in the 2013-2014 GTA for a
telecommunication tower corrosion management program. Corrosion issues required inspections and corrosion mitigation beyond that contemplated
in the forecast.
11
59943 Grande Prairie Area Telecom Reliability
-
2.3
(2.3) -100% Actual additions were lower than forecast due to a project schedule adjustment to allow time to explore other cost-effective solutions. Tower
estimates received during the preliminary design were significantly higher than anticipated. The timing of this project was also adjusted to coordinate
with the network multiplexer upgrade project (59955). This coordination minimizes rework by ensuring the project design incorporates the new
multiplexer platforms rather than obsolete multiplexers.
12
59955 Network Multiplexor Upgrade
4.5
3.3
13
14
DIRECT ASSIGNED PROJECTS SYSTEM
55125 Birchwood 240kV Line and Substation
-
74.1
(74.1) -100% Additions were lower than forecast due to a delay in the In Service Date (ISD) from 2014 to a later period as a result of refiling the Facilities
Application due to the suspension notice issued by the AUC in 2013, as well as the 2013/14 General Tariff Application (GTA) estimate including work
that was later moved to appropriation 55127.
15
55126 Ells – 9L76/9L08 240kV D/C Line
-
44.0
16
55322 Algar Area System Reinforcement
-
30.0
17
55585 North Fort McMurray Transmission Development
2.9
-
(44.0) -100% Additions were lower than forecast due mainly to the project ISD being deferred to a later period due to consultations with the AESO which resulted in
the Proposal to Provide Services (PPS) being submitted in December of 2014.
(30.0) -100% Additions were lower than forecast due to a delay in ISD from 2014 to a future period due to additional time being required to finalize the substation
location and 240 kV line route.
2.9 100% Additions are higher than planned due mainly to trailing costs for line materials related to prior year capitalizations.
1.2
37%
Actual additions were higher than forecast due mainly to an adjustment in project schedule, which occurred in previous years. This adjustment was
necessary to optimize resource utilization to better support direct assigned and other transmission capital maintenance projects.
SCHEDULE 4.3-T
ADDITIONS
Page 2 of 3
ATCO Electric Transmission (AET)
VARIANCE EXPLANATIONS OF CAPITAL ADDITIONS
FOR THE YEAR ENDED DECEMBER 31, 2014
($Millions)
Line
No. Project
Description
2014
2014
Variance
Actual Approved Actual to
Adds
Adds
Approved
18
55703 Heart Lake Station Expansion
19
55785 Kettle River Substation and 240kV Line Tap
49.4
-
20
56539 Cold Lake Development
14.7
(0.0)
21
22
23
57151 St. Paul Area – Watt Lake and Whitby Lake Substations
57157 St. Paul Substation and Line
57155 Cold Lake Area - Bourque-Bonnyville
5.3
108.5
8.0
40.0
24
57156 Kitscoty Area Development
25.0
-
25
26
27
28
DIRECT ASSIGNED PROJECTS - CUSTOMER
51184 Swan Hills Synfuel Generation Interconnection
55187 Service for MacKay SAGD
55622 Cheecham POD
(0.0)
-
5.3
4.5
16.5
29
30
55632 Surmount II (Stage 2)
55633 Surmount II (Stage 3)
34.5
-
12.7
31
55655 Bohn POD
18.3
0.0
32
55680 Hangingstone SAGD
21.1
30.9
33
34
35
55725 Saleski
56642 La Corey Capacity Upgrade
56660 Beartrap 144kV Line and New Substation
7.9
22.8
24.1
-
36
56728 Lindbergh 25kV Bus Addition
2.3
0.8
37
38
39
40
TRANSMISSION ISOLATED GENERATION
90136 CUL 43 Replacement
DIRECT GENERAL PP&E
81000 Tools and Equipment
-
5.3
7.2
2.7
4.5
10.2
8.5
1.7
2.2
4.5
(2.3)
1.8
-
1.8
1.3
-
1.3
41 84000
42
43 82502/
82532
44 82597
45
Transportation Equipment
SOFTWARE
Cyber Security Program
Oracle R12 Upgrade
82649 AET Accounting System
-
5.1
Var
%
Variance Explanation
(5.1) -100% Additions were lower than forecast due to a delay in ISD from 2014 to a later period as a result of additional time being required to complete
construction due to substation and line modifications being more extensive than anticipated.
49.4 100% Additions were higher than forecast mainly due to the ISD being delayed from 2013 to 2014 as a result of upgrading the access road to the Kettle
River substation from a winter road to an all season road. In addition, total project costs were higher than forecast as a result of the AUC directed
reductions to AET's forecasts that were not, in fact, achieved, and higher than planned costs for the all season access road to provide year round
access.
14.7
100% Additions were higher than forecast due mainly to Marguerite Lake Substation work and line 7L587 energization occurring in 2014 versus 2013, the
AUC directed reductions to AET's forecasts were not, in fact, achieved as well as higher salvage costs.
5.3 100% Additions were higher than forecast due mainly to energization occurring in phases with the Whitby Lake phase being deferred to 2014 from 2013.
(8.0) -100% Additions were lower than forecast due mainly to the delay associated with land consultations and attaining P&L.
68.5 171% Additions were higher than forecast due mainly to additions being delayed from 2013 to 2014 due to the permit and license taking longer than
anticipated, the AUC directed reductions to AET's forecasts that were not, in fact, realized, as well as higher construction tender prices, higher
brushing, access costs and land consultation costs.
25.0
100% Additions were higher than forecast due mainly to an ISD delay from 2013 to 2014 as a result of schedule complexities related to equipment from
other projects. Additions were also higher than approved due mainly to higher construction costs and the AUC directed reductions to AET's forecasts
that were not, in fact, realized.
(5.3) -100% Additions were lower than forecast due to the cancellation of the project at the request of the customer.
(4.5) -100% Additions were lower than forecast due to the ISD being delayed to 2015 to align with the customer's schedule.
(16.5) -100% Additions were lower than forecast due mainly to a delay in submitting the PPS due to additional time required to review design and scope issues
related to the right of way and line as well as the substation, resulting in ISD being delayed from 2014 to a later period.
34.5 100% Additions were higher than forecast due mainly to a delay in ISD to 2014 from 2013 to align with the customers schedule.
(12.7) -100% Additions were lower than forecast due mainly to work being deferred to a future period mainly as a result of delays in the Surmount II (Stage 2)
project.
18.3 100% Additions were higher than forecast due to a delay in ISD from 2013 to 2014 as a result of the AESO requiring additional time to review the Need
Identification Document (NID) and PPS estimates.
(9.8) -32% Additions were lower than forecast due mainly to lower construction costs associated with substation design changes as well as release of
contingency.
(24.1) -100% Additions were lower than forecast due mainly to the project being deferred at the customer's request.
7.9 100% Additions were higher than forecast as this customer project was not anticipated at the time of the 2013/14 GTA.
22.8 100% Additions were higher than forecast due mainly to a delay in ISD from 2013 to 2014 as a result of a delay in receiving P&L due to an AUC hearing
regarding the line route, as well as a restricted construction time frame as the area was environmentally sensitive.
1.5 195% Additions were higher than forecast due mainly to the GTA estimate being based on the OOM estimate which was lower than the PPS that was
submitted at a later date, as the OOM did not include substation expansion and access road. Additionally, the AUC directed reductions to AET's
forecasts were not, in fact, achieved.
(5.3) -100% Actual additions were lower than forecast because the project is currently on-hold to evaluate the transmission strategy for Jasper.
100% Additions were higher than forecast mainly due to the Transmission Asset Management project which was required to create an asset management
framework that meets international standard ISO55001 requirements.
20% Higher mainly due to the delay of certain equipment forecasted to be purchased in 2013 that was subsequently purchased in 2014.
-51% Additions are lower due to cost savings related to a downgrade in the test lab for the Physical Security Project, quicker execution on the Change and
Configuration Management Project and the automation of Maximo classification to cyber assets on the BES Asset Classification Project.
100% The version of Oracle that was previously used went unsupported in late 2014 as such a project was initiated in 2013 to upgrade to a new supported
version. The project was complete in 2014.
100% In 2013, a need was identified for the Transmission Division to report and function as a stand alone division. To accomplish this, a separate set of
books in Oracle was implemented for January 1, 2014 which is now supporting the management of the Transmission assets of the company.
SCHEDULE 4.3-T
ADDITIONS
Page 3 of 3
ATCO Electric Transmission (AET)
VARIANCE EXPLANATIONS OF CAPITAL ADDITIONS
FOR THE YEAR ENDED DECEMBER 31, 2014
($Millions)
Line
No. Project
Description
2014
2014
Variance
Actual Approved Actual to
Adds
Adds
Approved
46
47
BUILDINGS
85000 Land, Buildings and Structures
5.1
2.7
48
49
50
85030 Nisku Fabrication Building
85816 Drumheller Service Building - Administration Phase I
85829 High Level Service Building
1.8
-
3.7
3.4
2.4
Var
%
90%
Variance Explanation
Additions were higher mainly due to a Vegreville expansion and renovations to Standard Life Building (2nd floor) and ATCO Centre Building (4th floor)
to accommodate employee growth.
1.8 100% Additions were higher mainly due to construction of a material storage building for the Panel Shop in Nisku.
(3.7) -100% Expenditures were lower than forecast mainly due to a re-evaluation of requirements and alternatives.
(3.4) -100% Expenditures were lower than forecast mainly due to a re-evaluation of requirements and alternatives.
SCHEDULE 4.3T
CONTRIBUTION EXPENDITURES
Page 1 of 2
ATCO Electric Transmission (AET)
VARIANCE EXPLANATIONS OF CONTRIBUTION EXPENDITURES
FOR THE YEAR ENDED DECEMBER 31, 2014
($Millions)
Line
No.
1
2
3
4
5
Project
Description
51168
DIRECT ASSIGNED PROJECTS
Norcen Substation Capacity
51181
Carmon Creek Cogeneration
51184
Swan Hills Synfuel Generation Interconnection
51341
Buchanan Creek Substation
6
51680
7
2014
2014 Variance
Actual Approved Actual to Var
Expend Expend Approved %
Variance Explanation
3.4
-
3.4
100%
Expenditures were higher than forecast because the project was not anticipated at the time of the 2013/14 GTA.
10.9
-
10.9
100%
Expenditures were higher than forecast because the project was not anticipated at the time of the 2013/14 GTA.
-
2.0
(2.0)
-100%
Expenditures were lower than forecast as a result of the project being cancelled at the request of the customer.
5.4
-
5.4
100%
Brintnell Permanent Capacity Addition
(1.5)
-
(1.5)
-100%
Expenditures were lower than forecast because a refund was paid to the customer in 2014 based on final project costs that
were lower than forecast.
55147
55147 - 9L66 / 9L32 Line Relocation
(2.0)
-
(2.0)
-100%
Expenditures were lower than forecast because a contribution received in 2013 for 9L66/L32 was refunded to the customer as
the project was deferred.
8
55187
Service for MacKay SAGD
15.6
2.9
12.7
439%
Expenditures were higher than forecast due to higher project costs than forecast (see project 55187 Schedule 4.2T
Expenditures).
9
55325
Sweetheart Lake (Algar Expansion)
3.6
-
3.6
100%
Expenditures were higher than forecast because at the time of the filing, the contribution was anticipated to be paid post GTA
based on estimated investment levels.
10
11
55579
Secord Substation
5.4
-
5.4
100%
Expenditures were higher than forecast because the project was not anticipated at the time of the 2013/14 GTA.
55584
Green Stocking Substation
1.8
-
1.8
100%
Expenditures were higher than forecast because the customer changed their contracted load levels which resulted in
decreased investment and additional contribution.
12
55633
Surmount II (Stage 3)
14.6
9.8
4.8
100%
Expenditures were higher than forecast mainly due to expenditures delayed from 2013 as well as higher project costs (see
project 55633 Schedule 4.2T Expenditures).
13
55655
Bohn POD
(8.7)
-
(8.7)
-100%
Expenditures were lower than forecast mainly due to a refund to the customer based on lower project costs as a result of a
shorter line length as well as a release of contingency.
14
55680
Hangingstone SAGD
6.5
10.7
(4.2)
-39%
Expenditures were lower than forecast mainly due to lower project costs (see project 55680 Schedule 4.2T Expenditures).
This was partially offset by a higher contribution due to the actual allowed project investment decreasing based on the
October 1, 2013 AESO tariffs whereas the Approved Contribution was based on the 2012 Contribution Policy Application
where project investments levels were assumed to increase.
15
55725
Saleski
-
2.6
(2.6)
-100%
Expenditures were lower than forecast due mainly to the project being deferred at the customer's request (see project 55725
Schedule 4.2T Expenditures).
16
17
18
55748
Dover West Clastics
-
11.9
(11.9)
-100%
Expenditures were lower than forecast as a result of the project being cancelled at the request of the customer.
55751
Snipe Creek Sub and Line
-
4.4
(4.4)
-100%
Expenditures were lower than forecast as a result of the project being cancelled at the request of the customer.
56015
Norberg Substation and 144kV Line
(1.5)
-
(1.5)
-100%
Expenditures were lower than forecast as a result of a partial contribution refund issued to the customer based on lower
project costs.
19
20
21
56055
Weasel Creek POD
(3.0)
-
(3.0)
-100%
Expenditures were lower than forecast because of a refund paid based on final project costs.
56585
Taiga Substation and 144 kV Line
-
5.0
(5.0)
-100%
Expenditures were lower than forecast as a result of the project being cancelled at the request of the customer.
56642
La Corey Capacity Upgrade
2.7
-
2.7
100%
22
56660
Beartrap 144kV Line and New Substation
(6.1)
-
(6.1)
-100%
Expenditures were lower than forecast mainly because of a refund to the customer based on lower project costs due to the
release of contingency and a shorter line length.
23
56713
Irish Creek Capacity Upgrade
2.3
127%
Expenditures were higher than forecast because the forecast was based on proposed AESO tariffs included in the 2012
Contribution Policy Application and the actual expenditure was based on current approved AESO tariffs which came into
effect on October 1, 2013; decreasing investment levels. The contribution was also higher because project costs came in
higher than forecast (see project 56713 Schedule 4.2T Expenditures).
4.1
1.8
Expenditures were higher than forecast due mainly to the forecast being based on proposed AESO tariffs included in the
2012 Contribution Policy Application and the actual contribution being based on current approved AESO tariffs which came
into effect on October 1, 2013; decreasing investment levels. In addition the contribution was forecast to occur in 2013 but the
customer elected to pay in two instalments; deferring payment into 2014.
Expenditures were higher than forecast as this customer project was not anticipated at the time of the 2013/14 GTA (see
project 56642 Schedule 4.2T Expenditures).
SCHEDULE 4.3T
CONTRIBUTION EXPENDITURES
Page 2 of 2
ATCO Electric Transmission (AET)
VARIANCE EXPLANATIONS OF CONTRIBUTION EXPENDITURES
FOR THE YEAR ENDED DECEMBER 31, 2014
($Millions)
2014
2014 Variance
Actual Approved Actual to Var
Expend Expend Approved %
Variance Explanation
Line
No.
Project
24
56725
Lindbergh 144kV Line and Substation
(1.0)
-
(1.0)
-100%
Expenditures were lower than forecast because the customer increased their contracted load by 1.5MW which resulted in
increased investment and a partial customer contribution refund being issued.
25
26
56775
Bauer 144kV Line and Substation
(1.3)
-
(1.3)
-100%
Expenditures were lower than forecast because of a refund paid to the customer in 2014 based on final project costs.
58562
Hand Hills Wind Power Facility
0.7
6.1
(5.4)
-88%
Expenditures were lower than forecast due to the Facility Application being delayed while the AUC reviewed system access
issues (see project 58562 Schedule 4.2T Expenditures).
27
58902
Monitor Substation Capacity Upgrade
3.0
-
3.0
100%
Expenditures were higher than forecast as this customer project was not anticipated at the time of the 2013/14 GTA (see
project 58902 Schedule 4.2T Expenditures).
28
29
50020
Lines Capital Maintenance
2.8
10.3
(7.5)
-73%
Actual expenditures were lower than forecast due to a customer project, Ft McMurray Area Transmission Line Relocation,
being delayed to a future period.
30
50060
Substation Rebuilds
-
2.5
(2.5)
-100%
31
50010
Substation Capital Maintenance
1.4
-
1.4
100%
Description
OTHER TRANSMISSION
Actual expenditures were lower than forecast due to customer project, Steep Bank Substation Rebuild, being placed on hold.
Expenditures were higher than forecast as Lindbergh, Manning and other customers Distribution Generation projects were
not anticipated at the time of the 2013/2014 GTA.
ATCO Electric Transmission (AET)
VARIANCE EXPLANATIONS OF CONTRIBUTION ADDITIONS
SCHEDULE 4.3-T
CONTRIBUTION ADDITIONS
Page 1 of 2
FOR THE YEAR ENDED DECEMBER 31, 2014
($Millions)
Line
No.
Project
Description
2014
2014 Variance
Actual Approved Actual to Var
Adds
Adds Approved %
Variance Explanation
1
2
3
51184
51341
DIRECT ASSIGNED PROJECTS
Swan Hills Synfuel Generation Interconnection
Buchanan Creek Substation
7.0
5.3
3.5
(5.3)
3.5
-100%
99%
4
51680
Brintnell Permanent Capacity Addition
(1.5)
-
(1.5)
-100%
5
55187
Service for MacKay SAGD
-
4.5
(4.5)
-100%
6
55584
Green Stocking Substation
1.8
-
1.8
100%
7
55622
Cheecham POD
-
7.8
(7.8)
-100%
8
55632
Surmount II (Stage 2)
-
21.3
100%
9
55633
Surmount II (Stage 3)
12.7
(12.7)
-100%
10
11
55655
55680
Bohn POD
Hangingstone SAGD
25.7
12.3
(4.2)
100%
-16%
12
55725
Saleski
-
2.6
(2.6)
-100%
Additions were lower than forecast due mainly to the project being delayed at the customer's request (see project
55725 Schedule 4.2T Additions).
13
56015
Norberg Substation and 144kV Line
(1.5)
-
(1.5)
-100%
14
15
56055
56642
Weasel Creek POD
La Corey Capacity Upgrade
(3.0)
2.7
-
(3.0)
2.7
-100%
100%
Additions were lower than forecast as a result of a partial contribution refund issued to the customer based on lower
project costs.
Additions were lower than forecast because of a refund paid based on final project costs.
16
56660
Beartrap 144kV Line and New Substation
16.2
-
16.2
100%
Additions were higher than forecast due mainly to a change in the planned In-Service-Date from 2013 to 2014. In
addition, the actual contribution was higher than forecast because the forecast was based on proposed AESO tariffs
included in the 2012 Contribution Policy Application and the actual addition was based on current approved AESO
tariffs which came into effect on October 1, 2011; decreasing investment levels.
17
56713
Irish Creek Capacity Upgrade
2.3
127%
Additions were higher than forecast due mainly to the forecast being based on proposed AESO tariffs included in the
2012 Contribution Policy Application and the actual addition being based on current approved AESO tariffs which
came into effect on October 1, 2013; decreasing investment levels.
18
56725
Lindbergh 144kV Line and Substation
(1.0)
-100%
21.3
12.3
21.5
4.1
(1.0)
1.8
-
Additions were lower than forecast as a result of the project being cancelled at the request of the customer.
Additions were higher than forecast due mainly to the forecast being based on proposed AESO tariffs included in the
2012 Contribution Policy Application and the actual addition being based on current approved AESO tariffs which
came into effect on October 1, 2011; decreasing investment levels.
Additions were lower than forecast because of a partial contribution refund paid to the customer in 2014 due mainly
to lower final project costs.
Additions were lower than forecast due to the planned In-Service-Date being delayed to 2015 to align with the
customer's schedule (see project 55187 Schedule 4.2T Additions).
Additions were higher than forecast because the customer changed their contracted load levels which resulted in
decreased investment and additional contribution.
Additions were lower than forecast due to a change in the planned In-Service-Date from 2014 to a later period (see
project 55622 Schedule 4.2T Additions).
Additions were higher than forecast because the forecast was based on proposed AESO tariffs included in the 2012
Contribution Policy Application and the actual addition was based on current approved AESO tariffs which came into
effect on October 1, 2011; decreasing investment levels. The contribution was also higher due to higher project
costs (see project 55632 Schedule 4.2T Additions).
Additions were lower than forecast due to a change in the planned In-Service-Date from 2014 to a later period (see
project 55633 Schedule 4.2T Additions).
Additions were higher than forecast mainly due to a change in the planned In-Service-Date from 2013 to 2014.
Additions were lower than forecast due mainly to project costs coming in lower than forecast (see project 55680
Schedule 4.2T Additions). This was partially offset by a higher contribution due to the actual allowed project
investment decreasing based on the October 1, 2013 AESO tariffs whereas the Approved Contribution was based
on the 2012 Contribution Policy Application where project investments levels were assumed to increase.
Additions were higher than forecast as this customer project was not anticipated at the time of the 2013/14 GTA (see
project 56642 Schedule 4.2T Additions).
Additions were lower than forecast because the customer increased their contracted load by 1.5MW which resulted
in increased investment and a refund being issued.
ATCO Electric Transmission (AET)
VARIANCE EXPLANATIONS OF CONTRIBUTION ADDITIONS
SCHEDULE 4.3-T
CONTRIBUTION ADDITIONS
Page 2 of 2
FOR THE YEAR ENDED DECEMBER 31, 2014
($Millions)
Line
No.
Project
Description
2014
2014 Variance
Actual Approved Actual to Var
Adds
Adds Approved %
Variance Explanation
19
56775
Bauer 144kV Line and Substation
(1.3)
-
(1.3)
-100%
Additions were lower than forecast because of a refund paid to the customer in 2014 based on final project costs.
20
21
22
58925
-
1.6
(1.6)
-100%
Additions were lower than forecast because the project is currently on hold.
50020
Cavendish Substation
OTHER TRANSMISSION
Lines Capital Maintenance
10.3
(8.3)
-80%
Actual additions were lower than forecast due to customer project Ft McMurray Area Transmission Line Relocation
being delayed to a future period.
23
50060
Substation Rebuilds
-
2.5
(2.5)
-100%
Actual additions were lower than forecast due to Steep Bank Substation Rebuild customer project being placed on
hold.
2.0
SCHEDULE 5.0-T
ATCO Electric Transmission (AET)
SUMMARY OF UTILITY INCOME TAX
FOR THE YEAR ENDED DECEMBER 31, 2014
($Millions)
Line
No.
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
Description
CrossReference
2014
Actual
2014
Approved
2013
Actual
Var. Actual to
Approved
Var.
%
Current Tax
Federal Income Tax
Federal Taxable Income
Income Tax Rate
Total Federal Income Tax
(69.3)
15.0%
(10.4)
(2.5)
15%
(0.4)
(23.3)
15%
(3.5)
(66.8)
(10.0)
2683.1%
Provincial Income Tax
Federal Taxable Income
Add: CCA Federal Flowthrough
Less: CCA Provincial Flowthrough
Provincial Taxable Income
Income Tax Rate
Provincial Income Tax
Prior Year Adjustment
Total Current Tax
(69.3)
257.2
257.1
(69.2)
10.0%
(6.9)
0.0
(17.3)
(2.5)
218.9
218.9
(2.5)
10%
(0.2)
(0.6)
(23.3)
191.4
191.5
(23.5)
10%
(2.3)
(0.9)
(6.7)
244.7
15.0%
36.7
36.7
167.6
15.0%
25.1
25.1
183.0
15.0%
27.5
27.5
Future Tax
Temporary Differences
Income Tax Rate
Prior year adjustment
Total Future Tax
Other Items
Large Corporations Tax
Preferred Dividend Tax
Other
Total Other Items
Transmission Income Tax
Farms, Irrigation Transmission
Utility Income Tax Expense
Total Transmission Income Tax
Sch 1.0-T
Var. Actual to
Prior Year
Var.
%
2683.1%
(46.0)
(6.9)
197.2%
0.0%
197.2%
(66.8)
38.3
38.2
(66.7)
(6.7)
0.0
(16.7)
2683.1%
17.5%
17.5%
2679.0%
0.0%
2679.0%
100.0%
2677.4%
(46.0)
65.8
65.6
(45.8)
(4.6)
0.9
(10.6)
197.2%
34.4%
34.2%
195.1%
0.0%
195.1%
100.0%
157.2%
77.1
0.0%
11.6
11.6
46.0%
0.0%
46.0%
100.0%
46.0%
61.7
9.3
9.3
33.7%
0.0%
33.7%
100.0%
33.7%
0.0%
-7.0%
0.0%
-7.0%
0.0%
-19.4%
(1.1)
(1.1)
0.0%
-29.7%
(2.5)
-10.0%
2.7
2.7
2.9
2.9
3.8
3.8
22.1
27.4
24.5
(0.2)
(0.2)
(5.3)
0.3
0.3
0.2
(0.1)
-15.9%
0.1
35.6%
22.4
27.7
24.8
(5.4)
-19.3%
(2.4)
-9.6%
Working Paper
Reference
-29.7%
Variance Explanations
38
2014 Actuals are lower than Forecast by $5.4 mainly due to higher deductions for Capital Cost Allowance (CCA) and removal & abandonment costs partially offset by
39
a lower deduction of deferrals for income tax purposes.
AUC Rule 005 11
SCHEDULE 7.0
ATCO Electric Transmission (AET)
ANALYSIS OF AFFILIATE COST OF GOODS SOLD
FOR THE YEAR ENDED DECEMBER 31, 2014
($Millions)
Line
No.
1
2
3
4
5
6
7
8
9
10
11
12
Service
CrossReference
Affiliate
2014 Actual
Amount
2014 Approved
Amount
Transmission Affiliate Cost of Goods Sold
Operations & Maintenance
Operations & Maintenance
Operations and Metering Services
Operations & Maintenance
Other items individually less than $0.1
ATCO Power Canada Ltd.
ATCO Power (2000) Ltd.
ATCO Energy Services Ltd.
ATCO Electric Distribution
0.4
0.3
3.1
0.1
0.2
0.1
0.0
0.0
Isolated Generation Affiliate Cost of Goods Sold
Operations & Maintenance
Other items individually less than $0.1
ATCO Electric Distribution
0.3
-
4.2
0.3
Total Affiliate Cost of Goods Sold
Var. Actual to
Approved
0.2
(0.1)
0.3
3.1
0.1
0.3
3.9
Var.
%
Working Paper
Reference
114.9%
-100.0%
567.3%
100.0%
458.3%
100.0%
1372.8%
AUC Rule 005 13
SCHEDULE 7.1
ATCO Electric Transmission (AET)
ANALYSIS OF AFFILIATE COST OF GOODS SOLD (CORPORATE)
FOR THE YEAR ENDED DECEMBER 31, 2014
($Millions)
Line
No.
1
2
3
4
5
6
7
8
9
10
Nature of Service
Affiliate
Corporate Affiliate Cost of Goods Sold
Payroll Services
Payroll Services
Payroll Services
Administrative Services
Administrative Services
Administrative Services
Other
ATCO I-Tek Inc
ATCO Power Canada Ltd.
ATCO Structures & Logistics
Northland Utilities (NWT) Limited
Northland Utilities (Yellowknife) Limited
Yukon Electrical Company Limited
Various
Total Affiliate Cost of Goods Sold
CrossRef.
2014 Actual
Amount
2014 Approved
Amount
Var. Actual to
Approved
Var.
%
-
0.1
0.1
0.1
0.3
0.3
0.2
0.1
(0.1)
(0.1)
(0.1)
(0.3)
(0.3)
(0.2)
(0.1)
-100.0%
-100.0%
-100.0%
-100.0%
-100.0%
-100.0%
-100.0%
-
1.2
(1.2)
-100.0%
Working Paper
Reference
AUC Rule 005 13
SCHEDULE 8
ATCO Electric Transmission (AET)
SUMMARY OF PAYROLL AND MANPOWER STATISTICS
FOR THE YEAR ENDED DECEMBER 31, 2014
($Millions)
SALARIES, WAGES AND EMPLOYEE BENEFITS
Line
CrossNo.
Description
Reference
Gross Salaries and Wages
1
Transmission Operations
2
Transmission Capital
3
Transmission Corporate - Operations
4
Transmission Corporate - Capital
5
Salaries and Wages Charged to Utility Operations
6
7
8
Gross Employee Benefits
9
Transmission Operations
10
Transmission Capital
11
Transmission Corporate - Operations
12
Transmission Corporate - Capital
13
Benefits Charged to Utility Operations
14
EMPLOYEE ALLOCATION
Line
No.
15
16
17
18
19
20
Description
Manpower Statistics
Total Regular Employees (FTEs)
Total Temporary Employees (FTEs)
Total Manpower
Less:
Allocated to Non-regulated
Total Manpower - Utility Operations
CrossReference
2014
Actual
2014
Approved
2013
Actual
Var. Actual to
Approved
Var.
%
Var. Actual to
Prior Year
Var.
%
30.1
92.2
6.0
19.0
31.1
91.8
8.4
17.5
23.5
76.0
6.9
15.1
(1.1)
0.4
(2.3)
1.6
-3.5%
0.4%
-27.9%
8.9%
6.5
16.2
(0.9)
3.9
27.8%
21.3%
-12.8%
26.0%
147.3
148.8
121.5
(1.5)
-1.0%
25.8
21.2%
5.0
18.9
0.7
3.6
5.5
17.7
1.5
3.4
5.0
14.8
1.3
2.9
(0.5)
1.2
(0.8)
0.3
-9.1%
6.6%
-53.5%
8.2%
(0.1)
4.1
(0.6)
0.7
-1.3%
28.0%
-44.9%
24.3%
28.2
28.1
24.0
0.1
4.2
17.5%
2014
Actual
2014
Approved
2013
Actual
1,304.0
100.0
1,404.0
1,294.5
104.9
1,399.4
1,196.9
70.7
1,267.6
12.0
1,392.0
1,399.4
1,267.6
Var. Actual to
Approved
9.5
(4.9)
4.6
0.5%
Var.
%
0.7%
-4.7%
0.3%
Var. Actual to
Prior Year
107.2
29.2
136.4
Var.
%
9.0%
41.3%
10.8%
Working Paper
Reference
Working Paper
Reference
SCHEDULE 9
ATCO Electric Transmission (AET)
SUMMARY OF RESERVE/DEFERRAL ACCOUNTS
FOR THE YEAR ENDED DECEMBER 31, 2014
($Millions)
2014 Actual
Line
No.
1
2
3
4
5
6
7
8
9
Description
CrossRef.
Opening
Balance
Adds
Provision
2014 Approved
Adjustments
Ending
Balance
Opening
Balance
Adds
Provision Adjustments
Ending
Balance
List of Reserve/Deferral Accounts
Reserve for Injuries and Damages
(0.0)
(1.0)
1.0
-
(0.0)
(0.5)
(0.5)
1.0
-
0.0
Total Deferred Assets
(0.0)
(1.0)
1.0
-
(0.0)
(0.5)
(0.5)
1.0
-
0.0
Future Income Tax
37.5
-
25.2
-
62.6
37.5
-
25.2
-
62.6
Total Deferred Liabilities
37.5
-
25.2
-
62.6
37.5
-
25.2
-
62.6
AUC Rule 005 15
SCHEDULE 9.1
ATCO Electric Transmission (AET)
Summary of Pension Plan Contributions
For the Year Ended December 31, 2014
($Millions)
Line
ATCO Electric has provided the following information below in response to Direction 13 from AUC Decision 2010-189 which indicated:
No.
1
The Commission would also like to establish the ability to monitor contributions into the Pension Plan. In this regard the Commission directs ATCO Utilities in its respective
2
annual Rule 005: Annual Reporting Requirements of Operational and Financial Results (Rule 005) filings to include the following information:
3
4
i) The amounts contributed to the Pension Plan on a calendar year basis by each of the ATCO Utilities (broken down by utility) and the amounts contributed by the unregulated
5
companies participating in the Pension Plan collectively. In reporting these contributions, the report should separately identify, amounts contributed as service costs under each
6
of the DB Plan and the DC Plan and amounts contributed in respect of the DB Plan unfunded liability.
7
8
2014 Actual
Defined Benefit Pension Expense
9
10
11
ATCO Electric (Note 1)
Service Amount
3.8
12
ATCO Other
6.0
Defined Contribution Pension Expense
Special Payment
Total
Service Amount
0.6
6.6
11.1
1.0
7.0
14.0
Defined Contribution Pension Expense
Total
13
14
2014 Forecast (per ATCO Utilities 2014 Pension Common Matters Application)
15
16
Defined Benefit Pension Expense
17
18
ATCO Electric (Note 2)
Service Amount
3.8
19
ATCO Other
6.1
Special Payment
Service Amount
0.6
Note 3
4.4
0.9
Note 3
7.0
20
21
Note 1 - The actual defined benefit and defined contribution service amounts along with the special payment do not include amounts that are allocated from the ATCO Head office.
22
Note 2 - Per 2014 ATCO Utilities Pension Application, Exhibit 0007.00.ATCO GAS-3405, Appendix 2, Table "Annual Employer DB Contributions - Actual Results"
23
Note 3 - Not available given pension common matters application only addresses DB plan
24
25
26
ii) A reconciliation in respect of the previous calendar year, by utility, of amounts collected through rates in respect of pension funding obligations with amounts contributed to the
pension plan including amounts in the deferral account approved in accordance with this Decision.
27
28
2013 Reconciliation (ATCO Electric - Transmission):
29
30
2013 Special Payment Pension costs included in ATCO Electric Transmission's Revenue Requirement (Note 4)
2013 Actual Special Payment Pension contributions (Note 4)
31
2013 Actual Special Payment Pension contributions - allocated from ATCO Head Office (Note 5)
32
Less: COLA Adjustment @ 50% Per AUC Decision 2954-D01-2015
33
Refund/(collection) to / (from) customers
$1.8
$3.1
$0.1
($3.2)
$1.8
34
35
Note 4 - Per ATCO Electric Transmission 2013-2014 GTA Exhibit 0188.02.AE-1989, Schedule 29-6
36
Note 5 - Per ATCO Utilities 2013 Pension Application, Exhibit 0001.00.ATCO GAS-2954, Para 15
37
38
Accordingly the deferral account should be calculated as the annual difference between the amounts collected in rates in respect of the special payments and the special payment
39
amounts actually paid by ATCO Utilities pursuant to the Pension Valuation(s) accepted by the Superintendent of Pensions that were in force during such year.
40
41
2014 Reconciliation (ATCO Electric - Transmission):
42
2014 Special Payment Pension costs included in ATCO Electric Transmission's Revenue Requirement (Note 6)
$1.8
43
2014 Actual Special Payment Pension contributions (Note 7)
$0.6
44
2014 Actual Special Payment Pension contributions - allocated from ATCO Head Office @ 15.8% (Note 8)
45
Less: COLA Adjustment @ 50% Per AUC Decision 2954-D01-2015
46
Refund/(collection) to / (from) customers
$0.0
($0.6)
$1.8
47
48
Note 6 - Per ATCO Electric Transmission 2013-2014 GTA Exhibit 0005.00.AE-3337, Schedule 29-6
49
Note 7 - Per ATCO Utilities 2014 Pension Application, Exhibit 0001.00.ATCO GAS-3405, Para 14
50
Note 8 - Per 2014 ATCO Utilities Pension Application, Exhibit 0007.00.ATCO GAS-3405, Appendix 2, Table "Annual Employer DB Contributions - Actual Results" line "Corporate" multiplied by AET approved allocation percentage of 15.8%.
51
52
53
iii) Confirmation of the date of any actuarial valuation reports filed with the Superintendent of Pensions since the last Rule 005
filing, and the associated impact of any filings on the pension funding requirements of each of the ATCO Utilities.
54
55
56
The Mercer 2013 CU Pension Plan Report was filed with the Superintendent of Pensions in June, 2014. The required pension funding contributions for
ATCO Electric Transmission beginning January 1, 2014 are $3.9 million for current service and $0.6 million for special payments, inclusive of the Head office allocation.
AUC Rule 005 15
ATCO Electric Transmission (AET)
RECONCILIATION OF FINANCIAL REPORTING SCHEDULES TO AUDITED FINANCIAL STATEMENTS (TRANSMISSION & DISTRIBUTION)
FOR THE YEAR ENDED DECEMBER 31, 2014
INCOME STATEMENT ITEMS
($000s)
Line
No.
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
Description
CrossReference
Revenues
Audited
Intercompany
Financial
Statements
Eliminations
(see attached)
1,061.0
(360.9)
Distribution
Financial
Statements
840.4
Transmission
Financial
Statements
Cost of Sales
Fuel
(17.6)
(6.7)
(6.6)
10.1
2.2
0.9
1,061.0
(360.9)
840.4
2.3
(338.7)
341.0
2.3
(338.7)
341.0
581.4
-
9.3
-
1.3
7.9
9.3
-
1.3
7.9
223.5
150.2
Fuel Adjustment
Sch 1
Operating and Maintenance
356.9
(16.8)
FAS - Negative Salvage (Net Dismantling Costs) Reclass to Depreciation
Non-recovered (disallowed)
Farms Reclassification
Other
RID and Rate Case - Adjustment to Provision
Non Utility Costs
Credit Facility Reclass from Financing
Sch 1
Transmission Transmission
Utility
Utility
Adjustments
Total
581.4
Impact of AUC Decisions
Reclassification of Revenue Offsets
Amortization of Contributions - Reclassed to Depreciation
Settlement of Prior Year Deferral Balances
Deferral Revenue
Other
Sch 1
Schedule 10.0
Page 1 of 3
(17.8)
563.6
-
-
0.4
0.4
8.3
(25.6)
(5.2)
(4.1)
(1.5)
(1.1)
1.2
1.0
356.9
(16.8)
223.5
150.2
(35.4)
114.8
AUC Rule 005 16
ATCO Electric Transmission (AET)
RECONCILIATION OF FINANCIAL REPORTING SCHEDULES TO AUDITED FINANCIAL STATEMENTS (TRANSMISSION & DISTRIBUTION)
FOR THE YEAR ENDED DECEMBER 31, 2014
INCOME STATEMENT ITEMS
($000s)
Line
No.
35
36
37
38
39
40
41
42
43
44
45
46
47
48
49
50
51
52
53
54
55
56
57
58
59
60
61
62
63
64
65
66
67
68
69
70
71
72
73
74
75
Description
CrossReference
Depreciation and Amortization
Audited
Intercompany
Financial
Statements
Eliminations
(see attached)
202.6
(5.3)
Distribution
Financial
Statements
105.1
Transmission
Financial
Statements
23.0
7.6
3.3
0.8
(6.6)
Sch 1
Note 2
Sch 1
Revenue Offsets
202.6
(5.3)
105.1
102.8
94.2
-
28.5
65.7
94.2
-
28.5
65.7
-
-
-
-
Reclassification from Revenues
Return
-
-
-
-
395.7
-
141.0
254.7
395.7
-
141.0
254.7
117.5
-
57.1
60.4
Note 1
Sch 1
Note 1 - Return Adjustments
Long Term Debt & Other
Adjustment for IFRS IDC Treatment
Financing Other
Credit facility Reclass to O&M
130.9
(43.3)
(43.3)
22.4
Preferred Shares
Return on Equity
6.7
6.7
39.3
39.3
294.0
60.7
16.3
(1.0)
76.0
136.4
-
57.1
60.4
-
-
-
-
-
-
-
-
278.2
-
84.0
194.3
278.2
-
84.0
194.3
(44.4)
(44.4)
149.9
395.7
-
141.0
254.7
39.3
294.0
117.5
Note 2
Total Return Adjustments
28.1
6.7
Sch 1
Adjustments
Transmission Transmission
Utility
Utility
Adjustments
Total
102.8
FAS - Net Salvage
Pension Contribution Capitalized
Other
Farms Reclassification
Amortization of Contributions
Income Tax
Tax on Adjustments
Schedule 10.0
Page 2 of 3
7.7
7.7
7.7
AUC Rule 005 16
ATCO Electric Transmission (AET)
RECONCILIATION OF FINANCIAL REPORTING SCHEDULES TO AUDITED FINANCIAL STATEMENTS (TRANSMISSION & DISTRIBUTION)
FOR THE YEAR ENDED DECEMBER 31, 2014
INCOME STATEMENT ITEMS
($000s)
Line
No.
76
77
78
79
Description
CrossReference
Note 2 - Return on Equity Adjustments
Audited
Intercompany
Financial
Statements
Eliminations
(see attached)
Distribution
Financial
Statements
Transmission
Financial
Statements
Transmission Transmission
Utility
Utility
Adjustments
Total
(Return)
After tax
Before tax
Schedule 10.0
Page 3 of 3
Tax impact
Financing & Subs
80
Interest and Other
81
82
83
84
85
86
87
88
89
90
Preferred Dividends
AFUDC vs IDC
Income Tax
Income Tax (Provincial Future Tax for IFRS)
Income Tax (T2S1 Additions & Deductions Non Regulatory)
Income Tax (T2S1 Additions & Deductions Non IFRS)
Income Tax (T2S1 Other)
(76.0)
(57.0)
(19.0)
-
(7.7)
(7.7)
7.7
-
30.7
(0.2)
(0.7)
1.2
(30.7)
0.2
0.7
(1.2)
(2.8)
Other Income Statement Items
91
Revenue Tax Impact
(11.1)
(8.3)
92
O&M Tax Impact
(35.1)
26.3
8.8
93
94
95
Depreciation Tax Impact
28.0
(21.0)
(7.0)
(94.2)
(44.4)
(43.3)
AUC Rule 005 16
SCHEDULE 11
ATCO Electric Transmission (AET)
RECONCILIATION OF FINANCIAL REPORTING SCHEDULES TO AUDITED FINANCIAL STATEMENTS
(Transmission and Distribution)
FOR THE YEAR ENDED DECEMBER 31, 2014
BALANCE SHEET ITEMS
($000s)
Line
No.
Description
CrossReference
1 Assets
2
Current Assets
3
Cash and short term investments
5
Accounts receivable
6
Income taxes
7
Inventories
8
Prepaid expenses
10
11
Property, plant and equipment
12
Intangibles
13
14
Investments
15
16
Regulatory Assets
17
Deferred financing Charges
18
Other
19
20
Total assets
21
22
23 Liabilities
24
Current Liabilities
25
Bank Indebtedness
26
Short term advances from parent and affiliated corporations
27
Accounts payable and accrued liabilities
28
Owing to parent and affiliated corporations
30
Regulatory Liabilities
31
32
Future income taxes
34
Regulatory Liabilities
35
Long term debt
37
Other
38
39
Total Liabilities
40
41 Equity
42
Equity preferred shares to Parent Corporation
43
44
Class A and Class B shares owner's equity
45
Class A and Class B shares
46
Retained earnings
48
49
Total Equity
50
Total Liabilities and Share Owner's Equity
51
Audited
Financial
Statements
(see attached)
Adjustments
Total
38.9
192.3
1.9
31.0
3.3
(0.0)
35.7
(0.0)
0.0
0.0
38.9
228.0
1.9
31.0
3.3
8,415.9
229.4
(1,140.7)
(2.1)
7,275.2
227.3
117.2
(117.2)
-
-
440.4
25.2
10.3
440.4
25.2
10.3
9,029.9
(748.5)
8,281.4
19.5
2.9
488.0
22.1
-
(0.0)
0.0
52.2
175.3
42.9
19.5
2.9
540.3
197.4
42.9
469.5
4,304.4
889.3
(244.3)
173.1
(65.0)
(866.4)
225.2
173.1
4,239.4
22.9
6,195.6
(732.2)
5,463.5
142.0
1.7
143.7
1,212.4
1,479.9
0.0
(18.1)
1,212.4
1,461.8
2,834.3
(16.4)
2,817.9
9,029.9
(748.5)
8,281.4
AUC Rule 005 17
(as a corporation)
NON-CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2014
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ATCO Electric Ltd.
Non-Consolidated Statement of Earnings
(ThousandsofCanadi
anDol
l
ars)
Year Ended
December 31
Note
Revenues
2014
2013
6
1,061,006
931,985
7
122,405
101,683
9,280
202,567
19,395
115,746
118,437
70,625
10,447
174,933
15,532
115,934
571,076
505,908
Other income/ (expense)
489,930
(543)
426,077
(336)
Operating profit
489,387
425,741
6,702
(123,636)
(116,934)
6,207
(93,895)
(87,688)
372,453
94,205
338,053
85,622
278,248
252,431
Costs and expenses
Salaries, wages and benefits
Plant and equipment maintenance
Fuel costs
Depreciation and amortization
Franchise fees
Other
Interest income
Interest expense
Net finance income (costs)
14
Earnings before income taxes
Income taxes
8
Earnings for the year
See accompanying Notes to Non-consolidated Financial Statements.
1
ATCO Electric Ltd.
Non-Consolidated Statement of Comprehensive Income
(ThousandsofCanadi
anDol
l
ars)
Year Ended
December 31
2014
2013
Note
Earnings for the year
Other comprehensive income (loss), net of income taxes:
Items that will not be reclassified to earnings:
(1)
Gains/ (losses) on retirement benefit obligations
278,248
252,431
(5,333)
500
213
(213)
(5,120)
287
273,128
252,718
22
Items that are reclassified subsequently to earnings:
Cash flow hedges
Comprehensive income for the year
(1)
Net of income taxes of $1.8 million for the year ended December 31, 2014 (2013 - $0.2 million).
See accompanying Notes to Non-consolidated Financial Statements.
2
ATCO Electric Ltd.
Non-Consolidated Balance Sheet
(ThousandsofCanadi
anDol
l
ars)
December 31
2014
2013
Note
ASSETS
Current assets
Cash and cash equivalents
Accounts receivable
Income taxes
Inventories
Prepaid expenses
38,862
192,315
1,899
30,987
3,280
267,343
139,670
2,168
34,969
3,318
180,125
8,415,949
229,399
117,211
7,070,374
201,391
104,473
9,029,902
7,556,363
19,497
2,872
488,053
22,112
13,481
372
385,200
284
60,000
51,523
532,534
510,860
469,453
51,328
4,304,374
837,996
381,128
42,241
3,325,905
765,390
6,195,685
5,025,524
18
141,968
272,264
19
1,212,428
1,479,821
-
1,039,428
1,219,360
(213)
9
Non-current assets
Property, plant and equipment
Intangibles
Investments
10
11
12
Total assets
LIABILITIES
Current liabilities
Bank indebtedness
Short term advances from affiliate corporations
Accounts payable and accrued liabilities
Derivative liability
Current portion of long term debt
Owing to parent and affiliate corporations
13
13
17
14
Non-current liabilities
Deferred income tax liabilities
Retirement benefit obligations
Long term debt
Other liabilities
Total liabilities
8
22
14
16
EQUITY
Equity preferred shares to parent corporation
Class A and Class B share owner's equity
Class A and Class B shares
Retained earnings
Accumulated other comprehensive loss
2,692,249
2,258,575
Total equity
2,834,217
2,530,839
Total liabilities and equity
9,029,902
7,556,363
See accompanying Notes to Non-consolidated Financial Statements.
DIRECTOR
DIRECTOR
3
ATCO Electric Ltd.
Non-Consolidated Statement of Changes in Equity
(ThousandsofCanadi
anDol
l
ars)
Note
At December 31, 2012
Earnings for the year
Shares issued
Dividends on equity preferred shares
Other comprehensive income
Losses on retirement benefit obligations
transferred to retained earnings
At December 31, 2013
Earnings for the year
Shares issued
Redemption of preferred shares, net of
issue costs
Dividends on equity preferred shares
Other comprehensive loss
Loss on retirement benefit obligations
transferred to retained earnings
At December 31, 2014
Equity
Preferred
Class A and
Shares Class B Shares
Retained
Earnings
Accumulated
Other
Comprehensive
Loss
19
272,264
-
808,928
230,500
-
981,386
252,431
(14,957)
-
287
2,062,578
252,431
230,500
(14,957)
287
22
-
-
500
(500)
-
19
272,264
-
1,039,428
173,000
1,219,360
278,248
-
(213)
-
2,530,839
278,248
173,000
(130,296)
-
-
(2,704)
(9,750)
-
(5,120)
(133,000)
(9,750)
(5,120)
19
22
-
Total
Equity
-
-
(5,333)
5,333
-
141,968
1,212,428
1,479,821
-
2,834,217
See accompanying Notes to Non-consolidated Financial Statements.
4
ATCO Electric Ltd.
Non-Consolidated Statement of Cash Flows
(ThousandsofCanadi
anDol
l
ars)
Note
Operating activities
Earnings for the year
Adjustments for:
Depreciation and amortization
Income taxes
8
Year Ended
December 31
2014
2013
278,248
252,431
202,567
94,205
174,933
85,622
Contributions by utility customers for extensions to plant
16
95,824
184,932
Amortization of customer contributions
Net finance costs
Interest paid
16
(23,157)
116,934
(4,095)
(24,266)
87,688
(3,642)
8
(3,936)
721
(8,153)
2,072
757,311
(20,132)
751,617
34,211
737,179
785,828
(1,461,614)
(46,280)
37,775
(12,737)
(1,628,815)
(54,616)
(96,972)
(13,646)
(1,482,856)
(1,794,049)
985,000
(61,000)
173,000
(133,000)
(9,750)
(172,181)
(6,045)
770,000
230,500
(14,957)
(136,115)
(5,040)
776,024
844,388
30,346
(13,853)
(163,833)
149,980
16,493
(13,853)
Income taxes paid
Other
Changes in non-cash working capital
Cash flow from operations
23
Investing activities
Purchase of property, plant and equipment
Purchase of intangibles
Changes in non-cash working capital
Other
10
11
23
Financing activities
Issue of long term debt
Repayment of long term debt
Issue of Class A and B shares
Redemption of equity preferred shares
Dividends paid on equity preferred shares
Interest paid, net
Other
Cash position
14
14
19
18
20
(1)
(Decrease)/ increase
Beginning of year
End of year
(1)
Cash position includes cash and cash equivalents, short term advances to parent and affiliate corporations, bank
indebtedness and short term advances from affiliate corporations.
See accompanying Notes to Non-consolidated Financial Statements.
5
ATCO ELECTRIC LTD.
NOTES TO NON-CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2014
(Tabul
aramountsi
nthousandsofCanadi
andol
l
ars, exceptasotherwi
senoted)
1.
CORPORATE INFORMATION
Alberta-based ATCO Electric Ltd. ("the Corporation") is engaged in the transmission and distribution of electric
energy in the Province of Alberta. Its registered office is at 10035 105 Street NW, Edmonton, Alberta, T5J 2V6. The
Corporation is principally owned by CU Inc., which is controlled by Canadian Utilities Limited, which in turn is
principally controlled by ATCO Ltd. and its controlling share owner, R.D. Southern.
2.
BASIS OF PRESENTATION
FINANCIAL STATEMENT PRESENTATION
The non-consolidated financial statements are prepared according to International Financial Reporting Standards
(“IFRS”) as issued by the International Accounting Standards Board (“IASB”) and interpretations of the IFRS
Interpretations Committee (“IFRIC”).
Pursuant to the Corporation’s regulatory obligation to the Alberta Utilities Commission (“AUC”) and interested parties,
the Corporation is obliged to provide detailed information relating solely to the electric utility and not relating to nonregulated subsidiaries, nor electric utilities regulated by other jurisdictions. The Corporation has, therefore, exercised
the exemption from full consolidation of its investments in subsidiary corporations available under IAS 27. As a
result, the Corporation’s investments in subsidiary corporations are carried at the original cost and the earnings of the
subsidiary corporations are reflected in the determination of earnings of the Corporation only to the extent of
dividends received from the subsidiaries. Consolidated financial statements of the Corporation’s immediate parent,
CU Inc., that comply with IFRS are available for public use. CU Inc. is incorporated in Canada and its registered office
is at 1400, 909-11th Avenue, SW, Calgary, Alberta, T2R 1N6.
Management authorized the issue of the non-consolidated financial statements on April 29, 2015.
BASIS OF MEASUREMENT
The non-consolidated financial statements are prepared on a historic cost basis, except for derivative financial
instruments and employee retirement benefit liabilities.
Certain comparative figures have been reclassified to conform to the current year presentation.
USE OF ESTIMATES AND JUDGMENT
Management makes judgments, estimates and assumptions that affect the application of policies and reported
amounts of revenues, expenses, assets and liabilities, as well as the disclosure of contingent assets and liabilities.
Such estimates mainly relate to unsettled transactions and events at the date of the non-consolidated financial
statements. Facts and circumstances may change and actual results could differ from those estimates. Management
uses judgment and currently available information to make these estimates and these estimates are reviewed on an
on-going basis. Revisions to accounting estimates are recognized in the period in which the estimate is revised, if the
revision affects only that period, or in the period of the revision and future periods if the revision affects both current
and future periods. Note 4 outlines the significant judgments and estimates made by the Corporation.
3.
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
RATE REGULATION
The Corporation is regulated primarily by the AUC. The AUC administers acts and regulations covering such matters
as rates, financing, and service area.
6
Nature and economic effects of rate regulation
The Corporation’s distribution operations are under a form of rate regulation called Performance Based Regulation
(PBR). PBR allows the distribution operations of the Corporation the opportunity to recover prudently incurred costs
of providing regulatory services and generate a fair return on investment. Under PBR, revenue is determined by a
formula that adjusts customer rates for inflation and expected productivity improvements over a five-year period. The
current PBR period applies for five years from 2013 to 2017. Specifically, the PBR formula incorporates the following
factors:

Estimated annual inflation for input prices (I Factor)

Less an offset to reflect expected productivity improvements during the PBR plan period (X Factor)
PBR also includes mechanisms to allow companies to:

Recover capital expenditures not recoverable through the PBR formula that meet certain criteria (K Factor)

Recover from or refund to customers amounts outside of management’s control that are material, should not
significantly influence the I Factor, are prudently incurred, are recurring, and could vary greatly from year to year
(Y Factor), or are unforeseen, and not likely to recur (Z Factor)
The Corporation’s transmission operations are subject to a cost of service regulation under which the AUC
establishes the revenues required to: (1) recover forecast operating costs of providing the regulated service, including
depreciation and amortization and income taxes, and (2) provide a fair and reasonable return on utility investment, or
rate base. Since actual operating conditions may vary from forecast, actual returns achieved can differ from approved
returns.
Rate base is the investment in property, plant and equipment and intangible assets approved by the AUC. The
investment includes an allowance for working capital and is reduced by accumulated depreciation and amortization,
reserves for future removal and site restoration costs, and unamortized contributions by utility customers for plant
extensions. These operations earn a return on rate base intended to meet the cost of the debt and preferred share
components of rate base and to provide share owners with a fair return on the common equity component of rate
base.
The AUC approves rates of return for the debt and preferred share components of rate base which is based on
the historical and forecast weighted average cost of debt and preferred shares. The AUC also establishes the capital
structure.
The transmission operations of the Corporation seek approval for their revenue requirement either by submitting a
general tariff application to the AUC or negotiating settlement with interested parties. In the latter case, the AUC
monitors the negotiated settlement process and approves any agreement.. The AUC may approve interim rates or
the recovery of costs on a placeholder basis, subject to final determination.
Financial statement effects of rate regulation
In the absence of a rate-regulated standard under IFRS that the Corporation is eligible to adopt, the Corporation does
not recognize assets and liabilities from rate-regulated activities as may be directed by regulatory decisions. Instead,
the Corporation recognizes revenues in earnings when amounts are billed to customers consistent with the AUC
approved rate design (see revenue recognition policy below). Operating costs and expenses are recorded when
incurred. Costs incurred in constructing an asset that meets the asset recognition criteria, are included in the related
property, plant and equipment or intangible asset.
ADJUSTED EARNINGS
Financial information that adjusts IFRS results to show the effect of rate regulation is used by the Corporation’s
management to evaluate the performance of the Corporation. The Corporation’s management assesses performance
of operations principally on the basis of earnings adjusted for regulatory items as shown in the adjusted information
disclosed in Note 5.
7
REVENUE RECOGNITION
Revenues from the regulated distribution of electricity include variable charges, which are recognized on the basis of
meter readings upon delivery of electricity to customers and include an estimate of usage not yet billed, and fixed
charges, based on the provision of the distribution service during the period.
Revenues for the use of regulated electricity transmission facilities are based on an annual tariff and are recognized
evenly throughout the year.
Certain additions to property, plant and equipment are made with the assistance of non-refundable cash contributions
from customers. These contributions are made when the estimated revenue is less than the cost of providing service
or where customer needs special equipment. Since these contributions will provide customers with ongoing access
to the supply of electricity, they are classified as deferred revenues and are recognized in revenues over the life of
the related asset.
SHORT TERM EMPLOYEE BENEFITS
Short-term employee benefits are recognized as an expense in salaries, wages and benefits as employees render
service. These benefits include wages, salaries, social security contributions, short-term compensated absences,
incentives, and non-monetary benefits, such as medical care. Costs for employee services incurred in constructing an
asset that meets the asset recognition criteria are included in the related property, plant and equipment or intangible
asset.
FRANCHISE FEES
Municipal governments charge franchise fees to the utilities in Canada for the exclusive right to provide service in
their community. These costs are charged to customers through rates approved by the AUC. Franchise fee revenues
and expenses are, therefore, recognized separately and are not recorded on a net basis.
INCOME TAXES
Income taxes are the sum of current and deferred taxes. Income taxes are recognized in earnings, except to the
extent it relates to items recorded in Other Comprehensive Income (“OCI”).
Current tax is calculated on taxable earnings using rates enacted or substantively enacted at the balance sheet date
in the jurisdictions in which the Corporation operates.
Current tax assets and liabilities are offset to the extent the Corporation has the legal right to settle on a net
basis and the Corporation intends either to settle on a net basis or to realize the asset and settle the
liability simultaneously.
Deferred income taxes are provided, using the liability method, on differences at the balance sheet date between the
tax bases of assets and liabilities and their carrying amounts for accounting purposes (“temporary differences”).
Deferred income tax liabilities are recognized on all taxable temporary differences. Deferred income tax assets are
recognized on deductible temporary differences and carry forward balances of unused tax losses or credits only
to the extent that it is probable that taxable earnings will be available against which these items can be applied.
Deferred income taxes are calculated at the tax rates that are expected to apply in the period when the liability is
settled or the asset is realized, based on the tax rates that have been enacted or substantively enacted by the
balance sheet date. If the expected tax rates change, deferred income taxes are adjusted to the new rates and the
adjustment is booked to either earnings or equity, depending on the nature of the underlying temporary difference.
The carrying amount of deferred income tax assets is reviewed at each balance sheet date and reduced to the extent
that it is no longer probable that sufficient taxable earnings will be available to allow all or part of the deferred income
tax asset to be realized. Unrecognized deferred income tax assets are reassessed at each balance sheet date and
are recognized to the extent that it has become probable that future taxable earnings will allow the deferred income
tax assets to be realized.
Deferred income tax assets and liabilities are offset when there is a legally enforceable right to set off tax assets
against tax liabilities, and when they relate to income taxes levied by the same taxation authority.
CASH AND CASH EQUIVALENTS
Cash equivalents consist of bankers’ acceptances, certificates of deposit issued or guaranteed by credit worthy
financial institutions and federal government issued short term investments with maturities generally of 90 days or
less at purchase.
8
INVENTORIES
Inventories are valued at the lower of cost or net realizable value. The cost of inventories is assigned using the
weighted average cost method. Net realizable value is the estimated selling price in the ordinary course of business,
less variable selling expenses.
The cost of inventories is comprised of all costs of purchase and other costs to bring the inventories to their present
condition and location. Purchase costs consists of the purchase price, import duties, non-recoverable taxes,
transport, handling and other costs directly attributable to the purchase of finished goods, materials or services.
PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment are recorded at cost less accumulated depreciation and any recognized impairment
losses. Cost includes expenditures that are directly attributable to the purchase or construction of the asset, such as
materials, labour, interest incurred during construction and contracted services. Subsequent costs are included in the
asset’s carrying amount or recognized as a separate asset only when it is probable that future economic benefits will
flow to the Corporation and the cost can be measured reliably. The carrying amount of a replaced asset is
derecognized when replaced.
Major overhaul costs are capitalized and depreciated on a straight-line basis over the period to the next major
overhaul. The cost of repair and maintenance activities are expensed when incurred.
The Corporation allocates the amount initially recognized in property, plant and equipment to its significant
components and depreciates each component separately. Assets are depreciated mainly on a straight-line basis over
their estimated useful lives. No depreciation is provided on land and construction work-in-progress.
Borrowing costs attributable to a construction period of substantial duration are added to the cost of the asset. The
effective interest method is used to calculate capitalized interest using specified rates for specific borrowings and a
weighted average rate for general borrowings. Interest capitalization starts when borrowing costs and expenditures
are incurred at the onset of construction and ends when construction is substantially complete.
Depreciation periods for the principal categories of property, plant and equipment are shown in the table below:
Useful Life
Transmission equipment
Distribution equipment
Generation equipment
Buildings
Other
40 to 75 years
15 to 75 years
5 to 40 years
5 to 60 years
5 to 40 years
Average
Depreciation Rate
2.1%
2.5%
3.4%
2.7%
4.1% to 20.0%
Depreciation methods and the estimated residual values and useful lives of assets are reviewed on a regular basis.
Any changes in these accounting estimates are recorded prospectively.
INTANGIBLES
Intangible assets are recorded at cost less accumulated amortization and any recognized impairment losses. The
Corporation amortizes intangible assets on a straight-line basis over their useful lives. Software work-in-progress is
not amortized as the software is not available for use.
INVESTMENTS
The Corporation’s investments in subsidiary corporations are carried at the original cost and the earnings of the
subsidiary corporations are reflected in the determination of earnings of the Corporation only to the extent of
dividends received from the subsidiaries.
9
IMPAIRMENT OF PROPERTY, PLANT AND EQUIPMENT, INTANGIBLES AND INVESTMENTS
The Corporation continually monitors its operating facilities and the markets and business environment in which it
operates for indications of asset impairment. Indicators of impairment include: significant underperformance relative
to historical or projected operating results, substantial changes in the way an asset is used or in the Corporation’s
overall business strategy, major negative industry or economic trends, or adverse decisions by regulators. Where
necessary, the Corporation estimates the recoverable amount for the cash generating unit (CGU) to determine if an
impairment loss is to be recognized. These estimates are based on assumptions, such as the price for which the
assets in the CGU could be obtained or future cash flows that will be produced by the CGU, discounted at an
appropriate rate. Subsequent changes to these estimates or assumptions could significantly impact the carrying value
of the assets in the CGU.
Intangible assets with finite lives are tested for recoverability when events or circumstances indicate a possible
impairment. Impairment is assessed at the CGU level. An impairment loss is recognized in earnings when the CGU’s
carrying value is higher than its recoverable amount. The recoverable amount is the greater of the CGU’s fair value
less disposal costs and its value in use. An impairment loss may be reversed in whole or in part if there is objective
evidence that a change in the estimated recoverable amount is warranted.
PROVISIONS AND CONTINGENCIES
The Corporation recognizes provisions when three conditions exist: (1) a current legal or constructive obligation as a
result of a past event, (2) a probable outflow of economic benefits will be required to settle the obligation, and (3) a
reliable estimate of the obligation can be made. If the effect is material, provisions are determined by discounting the
expected future cash flows at a pre-tax rate that reflects current market assessments of the time value of money and
the risks specific to the liability. If discounting is used, the increase in the provision due to the passage of time is
recognized in interest expense.
A contingent liability is a possible obligation, and a contingent asset is a possible asset, that arises from past events
and whose existence will be confirmed only by the occurrence or non-occurrence of one or more uncertain future
events not wholly within the control of the Corporation. A contingent liability may also be a present obligation that
arises from past events that is not recognized because it is not probable that an outflow of economic resources will be
required to settle the obligation or the amount of the obligation cannot be measured reliably.
Neither contingent liabilities nor assets are recognized in the non-consolidated financial statements. However, a
contingent liability is disclosed, unless the possibility of an outflow of resources is remote. A contingent asset is only
disclosed where an inflow of economic benefits is probable.
Management evaluates the likelihood of the contingent events based on the probability of exposure to potential loss.
Actual results could differ from these estimates.
FINANCIAL INSTRUMENTS
The Corporation classifies financial instruments when they are first recognized as fair value through profit or loss,
available for sale, held to maturity investments or loans and receivables. Financial liabilities are classified as fair
value through profit or loss or amortized cost.
Fair value through profit or loss
Financial instruments classified as fair value through profit or loss, other than derivative instruments that are effective
hedging instruments, are measured at fair value. Changes in fair value are recognized in earnings.
Available for sale
Financial instruments classified as available for sale are measured at fair value using quoted prices in an active
market. When actively quoted prices are not available, fair value is determined using other valuation techniques. If
fair value cannot be reliably estimated, the item is carried at cost. Changes in fair value are recognized in other
comprehensive income.
Held to maturity
Financial instruments classified as held to maturity, loans and receivables or other liabilities are measured at
fair value upon initial recognition. Thereafter, they are measured at their amortized cost using the effective interest
method. Investments in equity instruments that do not have an actively quoted price and whose fair value cannot be
reliably measured are measured at cost.
10
Transaction costs
Transaction costs directly attributable to the purchase or issue of financial assets or financial liabilities that are not fair
value through profit or loss are added to the fair value of such assets or liabilities when initially recognized.
Transaction costs for long-term debt and preferred shares classified as liabilities are amortized over the life of the
respective financial liability using the effective interest method. The Corporation’s long-term debt and preferred
shares are presented net of their respective transaction costs.
Offsetting financial instruments
Financial assets and financial liabilities are offset and the net amount is reported in the balance sheet: (1) if there is a
legally enforceable right to offset the recognized amounts, and (2) If the Corporation intends either to settle on a net
basis or to realize the assets and settle the liabilities simultaneously.
IMPAIRMENT OF FINANCIAL INSTRUMENTS
Property, plant and equipment and intangible assets with finite lives are tested for recoverability when events or
circumstances indicate a possible impairment. Impairment is assessed at the Cash Generating Unit (CGU) level,
which is the smallest identifiable group of assets that generates independent cash inflows. An impairment loss is
recognized in earnings when the CGU’s carrying value is higher than its recoverable amount. The recoverable
amount is the greater of the CGU’s fair value less disposal costs and its value in use. An impairment loss may be
reversed in whole or in part if there is objective evidence that a change in the estimated recoverable amount is
warranted. A reversal of an impairment loss shall not exceed the carrying amount that would have been determined
(net of depreciation) had no impairment loss been recognized for the asset in prior years.
DERIVATIVE FINANCIAL INSTRUMENTS
The Corporation uses various instruments, including forward contracts, to manage the risks from fluctuating
exchange rates. All such instruments are used only to manage risk and not for speculative purposes.
Contracts settled net in cash or in another financial asset, other than certain non-financial derivative contracts that
meet the Corporation’s own use requirements, are classified as derivatives and are recognized and measured as
described in this policy.
The Corporation designates each derivative instrument as either a hedging instrument or a non-hedge derivative:
a) A hedging instrument is designated as either:
i) A fair value hedge of a recognized asset or liability, or
ii) A cash flow hedge of either:
 A firm commitment in the case of a foreign currency transaction or a highly probable forecast
transaction, or
 The variable future cash flows arising from a recognized asset or liability.
At inception of a hedge, the Corporation documents the relationship between the hedging instrument and the
hedged item, including the method of assessing retrospective and prospective hedge effectiveness. At the end of
each period, the Corporation assesses whether the hedging instrument has been highly effective in offsetting
changes in fair values or cash flows of the hedged item and measures the amount of any hedge ineffectiveness.
The Corporation also assesses whether the hedging instrument is expected to be highly effective in the future.
A hedging instrument is recorded on the non-consolidated balance sheet at fair value. Payments or receipts on
a hedging instrument that is determined to be highly effective as a hedge are recognized at the same time, and in
the same financial category as, the hedged item. Subsequent changes in the fair value of a fair value hedge are
recognized in earnings at the same time as the hedged item. For a cash flow hedge, the effective portion of
changes in fair value is recognized in other comprehensive income (loss) and is subsequently transferred to
earnings at the same time as the hedged item. The portion of the changes in fair value that are not effective at
offsetting the hedged exposure is recognized in earnings.
If a hedging instrument ceases to be highly effective as a hedge, is de-designated as a hedging instrument or is
settled prior to maturity, then the Corporation ceases hedge accounting prospectively for that instrument; for a
cash flow hedge, the gain or loss deferred to that date remains in accumulated other comprehensive income and
is transferred to earnings at the same time as the hedged item. Subsequent changes in the fair value of that
derivative instrument are recognized in earnings.
11
If the hedged item is sold, extinguished or matures prior to the termination of the related hedging instrument, or if it
is probable that an anticipated transaction will not occur in the originally specified time frame, then the gain or loss
deferred to that date for the related hedging instrument is immediately transferred from accumulated other
comprehensive income to earnings.
Hedge gains or losses that were recognized in other comprehensive income are added to the initial carrying
amount of a non-financial asset or non-financial liability when:
i) An anticipated transaction for a non-financial asset or non-financial liability becomes a specific firm
commitment for which fair value hedge accounting is applied, or
ii) A cash flow hedge of an anticipated transaction subsequently results in the recognition of the non-financial
asset or non-financial liability.
b) A non-hedge accounted derivative instrument is recorded on the non-consolidated balance sheet at fair value and
subsequent changes in fair value are recorded in earnings.
Non-performance risk, including the Corporation’s own credit risk, is considered when determining the fair value
of derivative financial instruments.
RETIREMENT BENEFITS
The Corporation participates, together with its ultimate parent corporation, Canadian Utilities Limited, and its affiliate
corporations, in a registered group defined benefit pension plan (“the Group Plan”). The assets of the Group Plan are
not segregated for each participating entity and are used to provide pensions to all members of this plan. In this
circumstance, the Corporation is required to account for the Group Plan as a defined contribution plan whereby
contributions are expensed as paid.
The Corporation participates, together with its ultimate parent corporation, Canadian Utilities Limited, and its affiliate
corporations, in other post employment benefit (“OPEB”) and non-registered group defined benefit pension plans.
These plans are administered on a combined basis, and the Corporation accrues for its obligations under these
plans. Costs of these benefits are determined using the projected unit credit method and reflect management’s best
estimates of wage and salary increases, age at retirement and expected health care costs. The Corporation consults
with qualified actuaries when setting the assumptions used to estimate benefit obligations and the cost of providing
retirement benefits during the period.
Accrued benefit obligations at the balance sheet date are determined using a discount rate that reflects market
interest rates on high quality corporate bonds that match the timing and amount of expected benefit payments.
For non-registered defined benefit pensions, the Corporation is assessed a percentage of the total cost of the plans.
Gains and losses resulting from experience adjustments and changes in assumptions used to measure the accrued
benefit obligations are recognized in OCI in the period in which they occur. Those gains and losses are transferred
directly to retained earnings.
Employer contributions to the defined contribution pension plan are expensed as employees render service.
For non-registered defined benefit pension plans and OPEB plans, service cost is recognized as an expense in
salaries, wages and benefits and net interest expense is recognized in interest expense. The cost of benefit pension
plans is recognized as an expense in salaries, wages and benefits. Past service costs are recognized immediately in
earnings in the period of a plan amendment. When retirement benefit costs for employee services are incurred in
construction constructing an asset and meets the asset recognition criteria, the are included in the related property,
plant and equipment or intangible asset.
RELATED PARTY TRANSACTIONS
Transactions with related parties that are in the normal course of business are measured at the exchange amount.
FOREIGN CURRENCY TR ANSL ATIO N
The non-consolidated financial statements are presented in Canadian dollars. Transactions denominated in foreign
currencies are translated at the rate of exchange in effect at the transaction date.
12
ACCOUNTING CHANGES NOT YET ADOPTED
Certain new or amended standards or interpretations have been issued by the IASB or IFRIC that do not need to be
adopted in the current period. The Corporation has not early adopted these standards or interpretations. There are no
standards or interpretations issued, but not yet effective, that the Corporation anticipates will have a material effect on
the non-consolidated financial statements once adopted.
4.
SIGNIFICANT JUDGMENTS, ESTIMATES AND ASSUMPTIONS
Management makes estimates and judgments that could significantly affect how policies are applied, amounts in the
non-consolidated financial statements are reported, and contingent assets and liabilities are disclosed. Most often
these estimates and judgments concern matters that are inherently complex and uncertain. Judgments and estimates
are reviewed on an on-going basis; changes to accounting estimates are recognized prospectively.
SIGNIFICANT ACCOUNTING JUDGMENTS
Impairment of long-lived assets
Indicators of impairment are considered when evaluating whether or not an asset is impaired. Factors which could
indicate an impairment exists include: significant underperformance relative to historical or projected operating
results, significant changes in the way in which an asset is used or in the Corporation’s overall business strategy,
significant negative industry or economic trends, or adverse decisions by the AUC. Events indicating an impairment
may be clearly identifiable or based on an accumulation of individually insignificant events over a period of time.
Measurement uncertainty is increased where the Corporation is not the operator of a facility. The Corporation
continually monitors its operating facilities and the markets and business environment in which it operates.
Judgments and assessments about conditions and events are made in order to conclude whether a possible
impairment exists.
Income taxes
The Corporation makes judgments with respect to changes in tax legislation, regulations and interpretations.
Judgment is also applied in estimating probable outcomes, when temporary differences will reverse and whether tax
assets are realizable.
When tax legislation is subject to interpretation, management periodically evaluates positions taken in tax filings and
records provisions where appropriate. The provisions are management’s best estimates of the expenditures required
to settle the present obligations at the balance sheet date, using a probability weighting of possible outcomes.
SIGNIFICANT ACCOUNTING ESTIMATES AND ASSUMPTIONS
Revenue recognition
An estimate of usage not yet billed is included in revenues from the regulated distribution of electricity. The estimate
is derived from unbilled electricity distribution services supplied to customers. This estimate is from the date of the
last meter reading and uses historical consumption patterns. Management applies judgment to the measure and
value of the estimated consumption.
Useful lives of property, plant and equipment and intangibles
Useful lives are determined on current facts and past experience, and consider the anticipated physical life of the
asset, current and forecasted demand and the potential for technological obsolescence.
Impairment of long-lived assets
The Corporation continually monitors its intangible assets and the markets and business environment in which it
operates for indications of asset impairment. Where necessary, the Corporation estimates the recoverable amount for
the CGU to determine if an impairment loss is to be recognized. These estimates are based on assumptions, such as
the price for which the assets in the CGU could be obtained or future cash flows that will be produced by the CGU,
discounted at an appropriate rate. Subsequent changes to these estimates or assumptions may significantly impact
the carrying value of the assets in the CGU.
13
Retirement benefits
Costs for the non-registered defined benefit pension and OPEB plans are determined using the projected unit credit
method and reflect management’s best estimates of investment returns, long-term inflation rate, wage and salary
increases, age at retirement, liability discount rates and expected health care costs. The Corporation consults with
qualified actuaries when setting the assumptions used to estimate benefit obligations and the cost of providing
retirement benefits during the period.
Income taxes
Management periodically evaluates positions taken in tax filings where tax legislation is subject to interpretation, and
records provisions where appropriate. The provisions are management’s best estimates of the expenditures required
to settle the present obligations at the balance sheet date measured using a probability weighting of possible
outcomes.
5.
ADJUSTED EARNINGS
Adjusted Earnings are earnings for the year after adjusting for the timing of revenues and expenses associated with
rate regulated activities and dividends on equity preferred shares of the Corporation. Adjusted Earnings also exclude
one-time gains and losses, significant impairments and items that are not in the normal course of business or a result
of day- to- day operations. Adjusted Earnings are a key measure of earnings used by the Chief Operating Decision
Maker (“CODM”) to assess performance and allocate resources. Other accounts in the non-consolidated financial
statements have not been adjusted as they are not used by the CODM for those purposes.
The reconciliation of adjusted earnings and earnings for the 2013 and 2014 year is below.
2014
Earnings for the year
Adjustments for rate regulated activities
Dividends on equity preferred shares
Adjusted earnings attributable to Class A and Class B share owners
2013
278,248
252,431
(626)
(9,750)
(19,575)
(14,957)
267,872
217,899
ADJUSTMENTS FOR RATE REGULATED ACTIVITIES
There is currently no specific guidance under IFRS for rate regulated entities that the Corporation is eligible to adopt.
Consequently, the Corporation does not recognize assets and liabilities arising from rate regulated activities under
IFRS.
Before adopting IFRS, the Corporation used standards issued by the Financial Accounting Standards Board (FASB)
in the United States (U.S.) as another source of generally accepted accounting principles (GAAP) to account for rateregulated activities. The CODM believes that earnings presented in accordance with the FASB standards are a better
representation of the Corporation’s rate-regulated activities. Therefore, the Corporation presents adjusted earnings
on this basis.
14
Rate regulated accounting differs from IFRS in the following ways:
Rate Regulated Accounting Treatment
IFRS Treatment
(1)
The Corporation defers the recognition of cash The Corporation records revenues when amounts are
received in advance of future expenditures.
billed to customers and recognizes costs when they are
incurred.
(2)
The Corporation recognizes revenues associated The Corporation records costs when incurred, but does
with recoverable costs in advance of future billings not recognize their recovery until changes to customer
to customers.
rates are reflected in future customer billings.
(3)
The Corporation recognizes the earnings that arise The Corporation recognizes earnings when customer
from a regulatory decision that pertained to current rates are changed and amounts are billed to customers.
and prior periods when the decision is received.
Timing adjustments for rate regulated activities are as follows:
Year Ended
December 31
2014
2013
Addi
ti
onalrevenuesbi
l
l
edi
ncurrentperi
od:
(1)
Future removal and site restoration costs
(2)
Retirement benefits
(3)
Finance costs on major transmission projects
(4)
Transmission capital deferral
Other
Revenuestobebi
l
l
edi
nfutureperi
od:
(5)
Deferred income taxes
(6)
Transmission access payments
Regul
atorydeci
si
ons:
(7)
Transmission access payments recoveries
Decisions related to current and prior periods
1,428
43,093
(6,030)
7,289
45,780
16,378
4,969
37,827
(13,736)
(4,491)
40,947
(56,866)
(7,336)
(64,202)
(45,209)
(46,065)
(91,274)
3,643
15,405
19,048
626
65,109
4,793
69,902
19,575
Descriptions of the adjustments and the timing of recovery or refund for each are as follows:
Description
Timing of Recovery or Refund
(1)
The removal and site restoration costs billed to
customers are the forecasted costs to be incurred
in future periods. Customers fund these expected
costs over the estimated useful life of the related
assets. Under rate-regulated accounting, billings to
customers in excess of costs incurred in the current
period are deferred.
(2)
Contributions to defined benefit pension plans and The deferred revenues will be recognized in adjusted
other post-employment benefit plans are billed to earnings as the variance between contributions and
customers when paid by the Corporation, whereas costs reverse over the service life of the plans.
the costs of retirement benefits are accrued over
the service life of the employees. Under rate
regulated accounting, contributions paid and billed
to customers in excess of costs accrued in the
current period are deferred.
The deferred revenues will be recognized in Adjusted
earnings when removal and site restoration costs are
incurred.
15
(3)
Finance costs incurred by the Corporation during
construction of major transmission capital projects
are billed to customers when incurred. Under rateregulated accounting, the finance costs billed to
customers are deferred.
(4)
For major transmission capital projects, the Recoveries from or refunds to the AESO of variances
Corporation’s billings to customers include a return between forecast and actual returns on rate base are
on forecast rate base. When actual capital costs expected to occur in the following year.
vary from forecast capital costs, the return on rate
base, and the resulting billings to the Alberta
Electric System Operator (AESO), will be higher or
lower than expected. Under rate-regulated
accounting, differences between billings to the
AESO and the return on actual rate base are
deferred.
(5)
Deferred income taxes are a non-cash expense The revenues will reverse when the temporary
resulting from temporary differences between the differences that gave rise to the deferred income taxes
book value and the tax value of assets and reverse in future periods.
liabilities. Income taxes are billed to customers
when paid by the Company. Deferred income
taxes are not billed to customers unless directed to
do so by the regulator. Under rate regulated
accounting, revenues are recognized in the current
period for the deferred income taxes to be billed to
customers in future periods.
(6)
The transmission access payments billed to
customers by ATCO Electric are the forecasted
payments to be incurred. Under rate-regulated
accounting, differences between actual costs
incurred and forecast costs billed to customers are
deferred for collection from or refund to customers
in future periods.
(7)
The Corporation recognizes revenues from
regulatory decisions when customer rates are
changed and amounts are billed to customers.
Under rate-regulated accounting, revenues from
regulatory decisions that affect current and prior
periods are recognized when the decision is
received.
The deferred revenues will be recognized in adjusted
earnings over the service life of the related assets.
Recoveries from or refunds to customers of differences
between transmission access payments billed to
customers and paid by ATCO Electric are expected to
occur in the next 6 to 12 months.
In the years ended December 31, 2014 and 2013,
actual payments for transmission access paid by the
Corporation exceeded forecast costs included in
billings to customers. These excess costs are
subsequently recovered from customers.
See note 25 Subsequent Events for further discussion.
6.
REVENUES
2014
2013
Tariff revenue
965,437
851,065
Franchise fees
25,261
21,793
Customer contributions
23,157
24,266
Other
47,151
34,861
1,061,006
931,985
16
7.
OTHER COSTS AND EXPENSES
2014
Goods and services
(1)
Property and other taxes
Rent and utilities
2013
70,232
74,672
39,320
33,595
6,194
7,667
115,746
115,934
(1) Goods and services include professional fees, contractor costs, technology related expenses, communications,
and other general and administrative expenses.
8.
INCOME TAXES
The components of income tax expense are summarized below:
Currentincom etaxexpense
Expense for the year
Deferred incom etaxexpense
Changes in temporary differences
2014
2013
4,205
6,017
90,000
94,205
79,605
85,622
The reconciliation of statutory and effective income tax expense is as follows:
2014
372,453
Earnings before income taxes
93,294
524
265
122
94,205
Income taxes, at statutory rates
Part VI.1 tax
Non-deductible differences
Other
2013
%
338,053
25.0
0.2
0.1
25.3
%
84,513,513 25.0
748
0.2
226
0.1
135
85,622
25.3
The combined Federal and Alberta statutory Canadian income tax rate did not change from 2013 to 2014.
The changes in deferred tax assets and liabilities are analyzed as follows:
Tax loss
carry
forwards
and tax
credits
Property,
plant and
equipment
Intangibles
288,158
23,841
(456)
(10,116)
301,427
Retirement
benefits
Total
Deferredi
ncometaxl
i
abi
l
i
ti
es:
At December 31, 2012
Charge (credit) to net earnings
90,547
(152)
(13,972)
3,182
79,605
Charge (credit) to other comprehensive income
-
-
-
160
160
Other
-
-
-
(64)
(64)
378,705
23,689
(14,428)
(6,838)
381,128
97,520
6,853
(18,611)
4,238
90,000
-
-
-
(1,675)
(1,675)
(7,299)
-
7,299
-
-
468,926
30,542
(25,740)
(4,275)
469,453
At December 31, 2013
Charge (credit) to net earnings
Charge to other comprehensive income
Other
At December 31, 2014
The Corporation does not expect any of its deferred income tax liabilities to reverse within the next 12 months.
17
As at the balance sheet date, the Corporation had $102.0 million in non-capital tax losses which, if unused, expire as
follows: 2031- $16.8; 2033- $44.8; 2034- $40.4.
In respect of these non-capital losses, the Corporation has recorded deferred income tax assets of
$25.2 million.
Income taxes paid amounted to $3.9 million (2013 ─ $8.2 million).
9.
INVENTORIES
Raw materials and consumables
2014
2013
30,987
34,969
For
the
year
ended December 31, 2014,
inventories
recognized as
an
expense
were
$9.9 million (2013 – $1.4 million). There have been no write-downs to net realizable value and there have been no
reversals of previous write-downs to net realizable value.
No inventories are pledged as security for liabilities.
10.
PROPERTY, PLANT AND EQUIPMENT
Utility
Transmission
and
Distribution
Equipment
Land and
Buildings
Construction
Work-inProgress
Other
Total
Cost:
At December 31, 2012
Additions
Disposals
5,046,755
1,383,972
(15,918)
296,841
46,574
(645)
1,284,840
179,669
-
308,308
81,126
(9,041)
6,936,744
1,691,341
(25,604)
At December 31, 2013
Additions
Transfers
Disposals
6,414,809
298,106
410,198
(24,974)
342,770
40,387
(208)
1,464,509
1,133,826
(420,268)
-
380,393
65,251
10,070
(5,637)
8,602,481
1,537,570
(30,819)
At December 31, 2014
7,098,139
382,949
2,178,067
450,077
10,109,232
Accumul
ateddepreci
ati
on:
At December 31, 2012
Depreciation
Disposals
1,235,078
128,667
(15,918)
36,613
7,320
(645)
-
122,907
27,126
(9,041)
1,394,598
163,113
(25,604)
At December 31, 2013
Depreciation
Disposals
1,347,827
150,801
(23,633)
43,288
11,501
-
-
140,992
28,352
(5,845)
1,532,107
190,654
(29,478)
At December 31, 2014
1,474,995
54,789
-
163,499
1,693,283
Netbookval
ue:
At December 31, 2013
At December 31, 2014
5,066,982
5,623,144
299,482
328,160
1,464,509
2,178,067
239,401
286,578
7,070,374
8,415,949
The cost of property, plant and equipment included $67.9 million (2013 – $57.9 million) of interest capitalized. The
average interest rate is 4.7% (2013 – 5.34%).
18
11.
INTANGIBLES
Computer
Software
Land Rights
Total
Cost:
At December 31, 2012
Additions
Disposals
161,334
26,437
-
92,052
28,179
(39)
253,386
54,616
(39)
At December 31, 2013
Additions
Disposals
187,771
31,131
-
120,192
15,149
(273)
307,963
46,280
(273)
At December 31, 2014
218,902
135,068
353,970
At December 31, 2012
Amortization
Disposals
75,723
14,870
-
14,422
1,596
(39)
90,145
16,466
(39)
At December 31, 2013
Amortization
Disposals
90,593
16,366
-
15,979
1,906
(273)
106,572
18,272
(273)
At December 31, 2014
106,958
17,612
124,571
97,178
111,944
104,213
117,456
201,391
229,399
Accumul
atedamorti
zati
on:
Netbookval
ue:
At December 31, 2013
At December 31, 2014
12.
INVESTMENTS
Investment in subsidiaries
Other
2014
2013
106,373
94,823
10,838
9,650
117,211
104,473
The investments in subsidiaries are as follows:
2014
Investee
The Yukon Electrical
Company Limited
Norven Holdings Inc.
13.
LINE
Principal place of business
Whitehorse, Yukon
Territory
Edmonton, Alberta
Percentage ownership
100%
100%
2013
Investment
67,921
38,452
106,373
58,471
36,352
94,823
BANK INDEBTEDNESS, SHORT TERM ADVANCES FROM AFFILIATE CORPORATIONS AND CREDIT
At December 31, 2014, bank indebtedness consists of $19,497 (2013 – $13,481), which represents cheques
outstanding in excess of cash in bank.
Short term advances from affiliate corporations are payable upon demand and bear interest based on short term
Bankers’ Acceptance rates.
The Corporation has an operating credit line of $10.0 million (2013 – $10.0 million), which is available on an
uncommitted basis. The credit line enables the Corporation to obtain financing for general business purposes. At
December 31, 2014, $5.8 million (2013 – $7.9 million) of the credit line was still available.
19
14.
LONG TERM DEBT (UNSECURED)
LONG TERM DEBT
Effective
Interest Rate
2014
2013
Debentures (due to CU Inc.) – unsecured
5.16%
-
60,000
2002 Series 6.145% due November 2017
6.22%
80,000
80,000
2004 Series 5.432% due January 2019
5.49%
58,500
58,500
1999 Series 6.8% due August 2019
6.86%
73,544
73,544
1990 Second Series 11.77% due November 2020
11.90%
38,243
38,243
2006 Series 4.801% due November 2021
4.85%
101,000
101,000
1991 Series 9.92% due April 2022
10.06%
50,010
50,010
1992 Series 9.40% due May 2023
9.51%
23,534
23,534
2009 Series 6.215% due March 2024
6.28%
116,000
116,000
2008 Series 5.563% due May 2028
5.61%
50,000
50,000
2004 Series 5.896% due November 2034
5.94%
121,100
121,100
2005 Series 5.183% due November 2035
5.23%
96,000
96,000
2006 Series 5.032% due November 2036
5.07%
101,000
101,000
2007 Series 5.556% due October 2037
5.60%
135,000
135,000
2008 Series 5.580% due May 2038
5.62%
75,000
75,000
2009 Series 6.500% due March 2039
6.55%
146,000
146,000
2010 Series 4.947% due November 2050
4.99%
125,000
125,000
2011 Series 4.543% due October 2041
4.58%
328,600
328,600
2011 Series 4.593% due October 2061
4.62%
131,400
131,400
2012 Series 3.805% due September 2042
3.84%
378,000
378,000
2012 Series 3.825% due September 2062
3.85%
151,000
151,000
2012 Series 3.857% due November 2052
3.89%
192,000
192,000
2013 Series 4.722% due September 2043
4.76%
470,000
470,000
2013 Series 4.855% due September 2063
4.90%
75,000
75,000
2013 Series 4.558% due November 2053
4.59%
225,000
225,000
2014 Series 4.085% due September 2054
4.12%
805,000
2014 Series 4.094% due October 2054
4.13%
180,000
Other long term obligation due July 2015, unsecured
3.00%
2004 Series 5.096% due November 2014
Less: Deferred financing charges
Total long term debt
3,500
4,500
(25,057)
(19,526)
4,304,374
3,385,905
-
(60,000)
4,304,374
3,325,905
Less current portion of long-term debt
Long term debt
-
CONTRACTUAL MATURITIES OF DEBT
The undiscounted contractual maturities of long term debt are as follows:
Long Term Debt
Principal
2015
Interest
-
208,778
2016
3,500
209,143
2017
80,000
209,038
2018
-
204,122
2019
132,044
202,532
4,113,886
4,479,741
4,329,430
5,513,354
2020 and thereafter
20
INTEREST EXPENSE
Interest expense is as follows:
Long term debt
Amortization of deferred financing charges
Other
Less: Interest capitalized (Note 10)
15.
2014
2013
184,224
147,731
637
465
6,642
3,626
191,503
151,822
(67,867)
(57,927)
123,636
93,895
CONTINGENCIES
Measurement inaccuracies occur from time to time with respect to the Corporation’s metering facilities. These
measurement adjustments are settled between the parties according to the Electricity and Gas Inspections Act
(Canada) and related regulations. The AUC may disallow the recovery of a measurement adjustment if it finds that
controls and timely follow-up are inadequate.
The Corporation is party to a number of disputes and lawsuits in the normal course of business. The Corporation
believes that the ultimate liability arising from these matters will have no material impact on the non-consolidated
financial statements.
The Corporation has a number of regulatory filings and regulatory hearing submissions before the AUC for which
decisions have not been received. The outcome of these matters cannot be determined.
In 2004, the Corporation transferred its retail energy supply business to Direct Energy Marketing Limited and one of
its affiliates (collectively “DEML”), a subsidiary of Centrica plc. The Corporation continues to own and operate the
electricity distribution systems used to deliver energy.
Although the Corporation transferred to DEML certain retail functions, including the supply of electricity to customers
and billing and customer care functions, the legal obligations of the Corporation remain if DEML fails to perform. In
certain events (including where DEML fails to supply electricity and the Corporation is ordered by the AUC to do so),
the functions will revert to the Corporation with no refund of the transfer proceeds to DEML by the Corporation.
Centrica plc, DEML’s parent, has provided a $300 million guarantee, supported by a $235 million letter of credit in
respect of DEML’s obligations to the Corporation and ATCO Gas in respect of the ongoing relationships
contemplated under the transaction agreements. However, there can be no assurance that the coverage under these
agreements will be adequate to cover all of the costs that could arise in the event of a reversion of such functions.
Canadian Utilities Limited has provided a guarantee of the Corporation’s payment and indemnity obligations to DEML
contemplated under the transaction agreements.
21
16.
OTHER LIABILITIES
Deferred revenues
Other
2014
2013
837,870
765,203
126
187
837,996
765,390
DEFERRED REVENUES
Deferred revenue is comprised of customer contributions for extensions to plant. These contributions are amortized
and recognized as revenue over the life of the related asset. Changes in deferred customer contributions are
summarized below.
Beginning of year
2014
2013
765,203
604,537
95,824
184,932
Amortization
(23,157)
(24,266)
End of year
837,870
765,203
Receipt of customer contributions
17.
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
The Corporation’s Board of Directors (“Board”) is responsible for understanding the principal risks of the
Corporation’s business, achieving a proper balance between risks incurred and the potential return to share owners,
and confirming that there are controls in place that effectively monitor and manage those risks with a view to the longterm viability of the Corporation. The Board has established a Risk Review Committee, which reviews significant
risks associated with future performance, growth and lost opportunities identified by management that could
materially affect the Corporation’s ability to achieve its strategic or operational targets. This committee is responsible
for confirming that management has procedures in place to mitigate identified risks.
INTEREST RATE RISK
The Corporation is not exposed to significant interest rate risk due to its long-term debt having fixed interest rates.
FOREIGN CURRENCY EXCHANGE RATE RISK
Foreign currency exchange rate risk arises from financial instruments denominated in a currency other than the
functional currency. The Corporation entered into foreign currency forward contracts to manage its exposure to
exchange rate risk arising on certain service agreements denominated in U.S. dollars in 2013. At December 31,
2014, the contracts consist of purchases of $nil U.S. in return for $nil Canadian dollars (2013 – $10.0 million).
CREDIT RISK
For cash and cash equivalents, short term advances to parent and affiliate corporations and accounts receivable,
credit risk represents the carrying amount on the balance sheet. Credit risk on cash and cash equivalents (when held
by the Corporation) is reduced by investing in instruments issued by credit worthy financial institutions and in federal
government issued short term instruments.
The maximum exposure to credit risk is the carrying value of loans and receivables and derivative financial
instruments. The Corporation does not have a concentration of credit risk with any counterparties.
Accounts receivable credit risk is reduced by financial security provided by the regulated rate provider and by retailers
in accordance with provisions contained within Electric Utilities Act Distribution Tariff Regulation A.R. 162/2003, and
the Corporation’s ability under the Regulation to recover through its distribution tariff any costs not recovered by a
claim against such retailer security.
Accounts receivable are non-interest bearing and are generally due in 30 days. The provision for impairment of credit
losses was $nil at December 31, 2014 (2013 - $ nil).
22
At December 31, 2014, the aging analysis of trade receivables that are past due but not impaired is as follows:
2014
30 to 90 days
Greater than 90 days
398
137
535
No impairments have been identified within accounts receivable.
LIQUIDITY RISK
Liquidity risk is the risk that the Corporation will not be able to meet its obligations associated with financial liabilities.
Cash flow from operations provides a substantial portion of the Corporation’s cash requirements. Additional cash
requirements are met through long-term debt borrowings from the parent corporation and the issuance of preferred
shares. The Corporation has a policy not to invest any of its cash balances in asset backed securities.
The Corporation has contractual obligations in the normal course of business; future minimum undiscounted
contractual maturities are as follows:
2020 and
2015
Bank indebtedness
Accounts
liabilities
payable
Owing to parent
corporations
Operating leases
and
and
(1)
Long term debt (Note 14)
Interest expense (Note 14)
2016
2017
2018
2019
thereafter
19,497
-
-
-
-
-
488,053
-
-
-
-
-
accrued
affiliate
22,112
-
-
-
-
-
9,695
7,329
5,401
4,775
579
673
-
3,500
80,000
-
132,044
4,113,886
208,778
209,143
209,038
204,122
202,532
4,479,741
100,658
-
-
-
-
-
9,916
-
-
-
-
-
858.709
219,972
294,439
208,897
335,155
8,594,300
Purchase obligations:
Capital expenditures
Other
(1)
Operati
ngl
easesarecompri
sedpri
mari
l
yofl
ongterm l
easesforoffi
cepremi
ses.
23
FAIR VALUE OF NON-DERIVATIVE FINANCIAL INSTRUMENTS
The fair value of cash and cash equivalents, accounts receivable, short term advances to parent and affiliate
corporations, accounts payable and accrued liabilities, short term advances from affiliate corporations, bank
indebtedness and owing to parent and affiliate corporations approximates carrying value due to the short term nature
of the financial instruments.
The fair values of the Corporation’s non-derivative financial instruments measured at other than fair value are as
follows:
Recurring measurements
Long term debt
(1)
2014
Carrying
Value
Fair Value
2013
Carrying
Value
Fair Value
4,325,930
3,325,905
4,917,131
3,532,206
(1)
Recorded atamorti
zed cost. Fai
rval
uesare determi
ned usi
ng quoted marketpri
cesforthe same orsi
mi
l
ar
i
ssues. W here the marketpri
ces are notavai
l
abl
e, fai
rval
ues are esti
mated usi
ng di
scounted cash fl
ow anal
ysi
s
basedontheCorporati
on’
scurrentborrowi
ngrateforsi
mi
l
arborrowi
ngarrangements.
FAIR VALUE OF DERIVATIVE FINANCIAL INSTRUMENTS
In 2013, the Corporation entered into several foreign currency forward contracts. The contracts had a notional
principal of $10.4 million, fair value payable at December 31, 2013 of $0.3 million and matured January 2014 through
November 2014. The fair value was determined using period-end market rates and approximated the amount the
Corporation would either pay or receive to settle the contract at December 31, 2013.
OFFSETTING FINANCIAL ASSETS AND LIABILITIES
The following trade receivables and payables are subject to offsetting, enforceable master netting arrangements and
similar agreements.
Gross amounts of recognized trade receivables
Gross amounts of recognized trade payables
Net amounts of trade receivables presented in the balance sheet
24
2014
2013
59,443
42,610
(22,251)
(22,292)
37,192
20,318
18.
EQUITY PREFERRED SHARES
CU INC. EQUITY PREFERRED SHARES
Authorized and Issued
Authorized: An unlimited number of Series Preferred Shares, issuable in series.
Issued:
Stated
Redemption
Value
Dates
2014
Shares
2013
Amount
Shares
Amount
(dollars)
Cumulative Redeemable Preferred Shares
4.60% Series 1
$25.00
See below
2,440,000
61,000
2,440,000
61,000
6.70% Series 2
$25.00
See below
-
-
5,320,000
133,000
3.80% Series 4
$25.00
See below
1,560,000
39,000
1,560,000
39,000
Issuance Costs
(1,702)
(4,406)
98,298
228,594
During the year, the Corporation redeemed 5,320,000 6.70% Series 2 Preferred shares in exchange for
$133,000.
Fair Values
Fair values for preferred shares determined using quoted market prices for the same or similar issues are $85 million
(2013 – $219.9 million).
Redemption Privileges
The Series 1 Preferred Shares are redeemable at the option of the Corporation commencing on June 1, 2012, at the
stated value plus a 4% premium per share for the next 12 months plus accrued and unpaid dividends. The
redemption premium declines by 1% in each succeeding twelve month period until June 1, 2016.
On June 1, 2016, and on June 1 of every fifth year thereafter, the Corporation may redeem the Series 4 Preferred
Shares in whole or in part at the stated value plus all accrued and unpaid dividends. Holders may elect to convert
any or all of their Series 4 Preferred Shares into an equal number of Cumulative Redeemable Preferred Shares
Series 5 (subject to certain restrictions) on June 1, 2016, and on June 1 of every fifth year thereafter. Holders of the
Series 5 Preferred Shares will be entitled to receive, as when declared by the Board of Directors of the Corporation,
floating rate cumulative preferential cash dividends, payable quarterly for an initial period of five years at a rate equal
to the then current 3-month Government of Canada Treasury Bill yield plus 1.36%. On June 1, 2021, and on June 1
of every fifth year thereafter (“Series 5 Conversion Date”), holders of the Series 5 Preferred Shares may elect to
convert any or all of their Series 5 Preferred Shares back into an equal number of Series 4 Preferred Shares. On
June 1, 2021, or thereafter, the Corporation may redeem the Series 5 Preferred Shares in whole or in part at $25.00
on a Series 5 Conversion Date or at $25.50 on any other date.
25
CANADIAN UTILITIES LIMITED EQUITY PREFERRED SHARES
Authorized and Issued
Authorized: An unlimited number of Series Second Preferred Shares, issuable in series.
Issued:
Stated
Redemption
Value
Dates
2014
Shares
2013
Amount
Shares
Amount
1,748,578
43,714
(dollars)
Perpetual Cumulative Second Preferred Shares
4.00% Series V
$25.00
October 3, 2017
1,748,578
43,714
Issuance Costs
1,748,578
(44)
(44)
43,670
43,670
The dividends payable on the Series V Preferred Shares are fixed until the redemption date specified above, at which
time a new dividend rate may be established by negotiations between the Corporation and the ultimate holders of the
shares.
Effective October 3, 2012, the dividend rate on the Series V Perpetual Cumulative Second Preferred Shares was set
to 4.00% per annum with a redemption date of October 3, 2017.
Fair Values
Fair values for preferred shares determined using quoted market prices for the same or similar issues are $45.1
million (2013 - $43.7 million).
Redemption Privileges
The preferred shares are redeemable on the date specified above at the option of the Corporation at the stated value
plus accrued and unpaid dividends.
19.
CLASS A AND CLASS B SHARES
AUTHORIZED AND ISSUED
Authorized:
Class A Non-Voting
Class B Common
Total
Shares
Shares
Shares
Amount
Unlimited
Amount
Amount
Unlimited
Issued and outstanding:
December 31, 2013
Shares issued
December 31, 2014
22,974,277
636,437
14,081,009
402,991
37,055,286
1,039,428
624,331
107,261
382,654
65,739
1,006,985
173,000
23,598,608
743,698
14,463,663
468,730
38,062,271
1,212,428
On December 23, 2014, the Corporation issued 624,331 Class A non-voting common shares and 382,654 Class B
common shares to its parent for approximately $171.80 per share.
26
20.
DIVIDENDS
Cash dividends declared and paid per share for all series and classes of preferred shares are as follows:
2014
2013
(dollars per share)
Equi
typreferredsharestoparentcorporati
on:
4.60% Cumulative Redeemable Preferred Shares, Series 1
1.1500
1.1500
6.70% Cumulative Redeemable Preferred Shares, Series 2
0.8375
1.6750
3.80% Cumulative Redeemable Preferred Shares, Series 4
0.9500
0.9500
4.00% Perpetual Cumulative Second Preferred Shares, Series V
1.0000
1.0000
The payment of dividends on the Corporation’s Class A and Class B shares and equity preferred shares is at the
discretion of the Board and depends on the financial condition of the Corporation and other factors.
21.
CAPITAL DISCLOSURES
The Corporation’s objective when managing capital is to remain within the capital structure approved by the AUC,
which, through the generic cost of capital decision issued in 2011, established the capital structure for the
Corporation. The AUC approved equity ratio for the Corporation’s transmission and distribution operations were 37%
(2013 – 37%) and 39% (2013 – 39%) respectively, and the Corporation is capitalized consistent with the generic cost
of capital decision. The capitalization involves the use of long term debt and preferred share financings. See Note
25 Subsequent Events for further discussion.
The Corporation includes share owner’s equity, preferred shares, and long term debt, as adjusted in accordance with
the FASB standards (see Note 5), in its determination of capitalization. In maintaining or adjusting its capital
structure, the Corporation may adjust the amount of dividends paid to the share owner, issue or purchase Class A
and Class B shares, and issue or redeem preferred shares and long term debt.
22.
RETIREMENT BENEFITS
The Corporation, together with its ultimate parent, Canadian Utilities Limited, and affiliate corporations, maintains
registered defined benefit and defined contribution pension plans for most of its employees. It also provides other
post employment benefits, principally health, dental and life insurance, for retirees and their dependents. The defined
benefit pension plans provide for pensions based on employees’ length of service and final average earnings.
As of 1997, new employees automatically participate in the defined contribution pension plan. Employees
participating in the defined benefit pension plans may transfer to the defined contribution pension plans at any time.
Upon transfer, further accumulation of benefits under the defined benefit pension plans ceases.
The Corporation, together with its ultimate parent, Canadian Utilities Limited, and affiliate corporations, also maintains
non-registered, non-funded defined benefit pension plans for certain officers and key employees.
Contributions to the Group Plan, which is accounted for as a defined contribution pension plan, are expensed as paid.
Other post employment benefit (“OPEB”) and non-registered group defined benefit pension plans, which the
Corporation funds out of general revenues, are administered on a combined basis with the Corporation’s parent and
affiliate corporations. For OPEB, the accrued liabilities and costs are determined on a Corporation-by-Corporation
basis; for non-registered defined benefit pensions, the Corporation is assessed a percentage of the total costs of the
plans.
27
THE CORPORATION’S BENEFIT PLANS
Information about the Corporation’s participation in the benefit plans, in aggregate, is as follows:
2014
Pension
Benefit
Plans
2013
Other Post
Employment
Benefit Plans
Pension
Benefit Plans
Other Post
Employment
Benefit Plans
Components of benefit plan cost:
Defined benefit plans cost
15,730
2,314
24,052
2,136
Defined contribution plans cost
13,273
-
11,794
-
Total benefit plans cost
29,003
2,314
35,846
2,136
(19,136)
(1,515)
22,583
1,346
9,867
799
13,263
790
Beginning of year
14,823
27,418
14,845
26,145
Total benefit plans cost
15,730
2,314
24,052
2,136
(15,415)
(743)
(23,583)
(694)
2,068
5,043
(491)
(169)
17,206
34,032
14,823
27,418
Less: Capitalized
Net cost recognized
Accrued benefit obligations
Benefit payments
(Gains)/ losses on accrued benefit obligations
End of year
WEIGHTED AVERAGE ASSUMPTIONS
2014
Other Post
Pension
Employment
Benefit
Benefit
Plans
Plans
2013
Other Post
Pension
Employment
Benefit
Benefit
Plans
Plans
Assumpti
onsregardi
ngbenefi
tpl
ancost:
Discount rate for the year
Average compensation increase for the year
Assumpti
onsregardi
ngaccruedbenefi
tobl
i
gati
ons:
Liability discount rate at December 31
Long term inflation rate
(1)
(2)
4.9%
(1)
Note
4.9%
4.3%
(1)
Note
4.3%
4.0%
2.0%
4.0%
(2)
Note
4.9%
2.0%
4.9%
(2)
Note
Theassumedaveragecompensati
oni
ncreasei
s3.25% for2014 andthereafter(2013 –3.25% andthereafter)
Theassumedannualheal
thcarecosttrendratei
ncreasesusedi
nmeasuri
ngtheaccumul
atedOPEB obl
i
gati
onare
asfol
l
ows: fordrugcosts, 5.83% for2013 gradi
ngdownovertenyearsto4.5% (2013 –5.9 7% for2013 gradi
ngdown
overel
evenyearsto4.5% ), forothermedi
calcosts, 4.5% for2014 andthereafter(2013 –4.5% for2013 and
thereafter), andfordentalcosts, 4.0% for2014 andthereafter(2013 –4.0% for2013 andthereafter).
In 2014, the Corporation adopted the Private Sector Canadian Pensioners Mortality table published by the Canadian
Institute of Actuaries as the basis for assumption regarding future life expectancy. In 2013, assumptions regarding
future life expectancy were based on a 1994 mortality table, updated for improvements in life expectancy.
28
FUNDING
Employees contribute a percentage of their salary to registered pension plans. The Corporation contributes its share
of contributions for the defined contribution pension plans. The Corporation also provides the balance of the funding
necessary to ensure that benefits will be fully provided for the defined benefit pension plans.
In 2014, an actuarial valuation for funding purposes as of December 31, 2013 was completed for the registered
defined benefit pension plans. The 2014 amount is also the estimated contribution for 2015. The next actuarial
valuation for funding purposes must be completed as of December 31, 2016.
For purposes of any pension funding requirements, the AUC has directed that the cash basis of accounting be used
in customer rate applications. Accordingly, the Corporation includes the cost of funding in its rate applications to the
AUC. As a result of the 2011 decision on the utilities’ pension methodology, the AUC decided that the appropriate
level for annual cost of living allowance adjustments is 50% of the Consumer Price Index to a maximum of 3%. This
decision impacts the recovery from customers of current service contributions in 2012 and, starting in 2013, special
payments and current service contributions.
C AN ADI AN UTILITIES LIM ITED BENEFI T PL ANS
Information about the plans as a whole, in aggregate, can be found in the Canadian Utilities Limited consolidated
financial statements for the year ended December 31, 2014.
23.
CHANGES IN NON-CASH WORKING CAPITAL
2014
Operati
ngacti
vi
ti
es, changesrel
atedto:
Accounts receivable
Inventories
Prepaid expenses
Accounts payable and accrued liabilities
Owing to parent and affiliate corporations
(34,936)
264
38
46,382
(31,880)
(20,132)
Investi
ngacti
vi
ti
es, changesrel
atedto:
Inventories
Accounts payable and accrued liabilities
29
2013
13,583
(882)
(122)
21,996
(364)
34,211
3,715
34,060
(9,654)
(87,318)
37,775
(96,972)
24.
RELATED PARTY TRANSACTIONS
2014
2013
68
45
Other expenses
25,154
25,865
Property, plant
and equipment
8,667
7,735
Accounts
receivable
19,289
-
Administration, financial
management, engineering
services, materials
management and metering
services
Revenues
1,451
1,312
Sale of equipment
Revenues
-
6
Entity
Relationship
Transaction
Recorded as
CU Inc. / Canadian
Utilities Limited /
ATCO Ltd.
Ultimate
Parent
Administration and rent
Revenues
Administration, financial
management, aircraft and
rent
Aircraft, rent and leasehold
improvements
Project costs
Northland Utilities
Enterprises Ltd.
Subsidiary
The Yukon Electrical
Company Limited
Subsidiary
Administration, financial
management, materials
management and metering
services
Revenues
1,019
1,153
Norven Holdings Inc.
Subsidiary
Administration and financial
management
Revenues
4
-
ATCO I-Tek
Affiliate
Administration
Revenues
70
117
Computer services
Other expenses
13,482
16,743
Property, plant
and equipment
6,810
19,973
16,524
19,135
Intangibles
ATCO Structures &
Logistics
ATCO I-Tek Business
Services Ltd.
ATCO Gas
Affiliate
Affiliate
Affiliate
Administration and camp
services
Revenues
210
536
Trailer supply and noise
management services and
purchase of equipment
Property, plant
and equipment
510
14,804
Billing and call centre
services
Other expenses
7,869
7,873
Computer system
development
Intangible
assets
1,457
1,929
Purchase of furniture
Property, plant
and equipment
6
-
Administration and rent
Revenues
353
378
Other expenses
570
560
Property, plant
and equipment
384
852
Administration, rent, joint
trenching, electronics and
instrumentation testing and
purchase of equipment
30
Entity
Relationship
Transaction
Recorded as
2014
2013
ATCO Power
Affiliate
Operate and maintain
substations, administration,
procurement services,
metering services and
communication services
Revenues
2,162
529
Rent
Other expenses
2
2
Purchase of equipment and
project costs
Property, plant
and equipment
27
145
Retail Services
Revenues
4,116
3,179
Spruce Meadows
Affiliate
Sponsorship, advertising
and promotion
Other expenses
236
216
ATCO Energy
Solutions Ltd.
Affiliate
Operate and maintain
facilities, project services,
communication services and
administration
Revenues
354
282
-
18
Property, plant
and equipment
Administration
Other expenses
27
26
ATCO Real Estate
Holdings Ltd.
Affiliate
Facility support
Revenues
17
-
ATCO Investments
Ltd.
Affiliate
Rent
Other expenses
31
29
ATCO Pipelines
Affiliate
Engineering and land
management
Property, plant
and equipment
-
27
Alberta Power (2000)
Ltd.
Affiliate
Administration, metering
services, communication
services and rent
Revenues
4
4
All of the above transactions are considered to be in the normal course of business and are measured at the
exchange amount being the amount of consideration established and agreed to by the related parties.
Trade receivables and payables with related parties are generally due within 30 days or less from the date of the
transaction. The amounts outstanding are unsecured, bear no interest and will be settled in cash. No provisions are
held against receivables from related parties.
31
25. SUBSEQUENT EVENTS
In March 2015, the Corporation received the AUC 2013 Generic Cost of Capital (GCOC) decision. The decision
established the return on equity (ROE) and deemed common equity ratios for the Corporation for 2013 to 2015. The
ROE was set at 8.3 per cent for each of 2013, 2014 and 2015, which is a reduction from the 8.75 per cent previously
approved. The GCOC decision also reduced the Utilities’ deemed common equity ratios by 1 per cent from what was
previously approved. These rates will remain in place on an interim basis for 2016 and subsequent years unless
otherwise directed by the AUC. This decision reduced first quarter adjusted earnings by $28.2 million. Of this amount,
$3.8 million related to the first quarter of 2015 and $24.4 million to prior years.
Also during March 2015, the Corporation received the AUC's PBR Capital Tracker decisions for 2013 to 2015 for
distribution operations. These decisions included approval of incremental funding for substantially all of the
distribution applied for Capital Tracker programs. However, the decisions will result in lower Capital Tracker rates
than previously approved due to the AUC requiring the utilities to use the actual cost of debt in the rate
determinations, which was lower than the forecast cost of debt that was previously being used. The impact of the
GCOC decision will also result in lower Capital Tracker rates. This decision reduced first quarter adjusted earnings by
$4.4 million. Of this amount, only $0.2 million related to the first quarter of 2015 and $4.2 million to prior years.
Had the financial statements been adjusted for the impact of these decisions, Adjusted Earnings, as reported in Note
5, would have been reduced by $28.6 million ($24.4 million for the GCOC decision, of which $13.6 million relates to
2014 and $10.8 million relates to 2013, and $4.2 million for the Capital Tracker decision, of which $2.7 million relates
to 2014 and $1.5 million relates to 2013).
32