TR12 Segmentation Presentation for Customer Meeting on Oct 7th

1
BPA Rate Case Customer Meeting Cost of Service
Analysis Sponsored by Transmission
Services October 7, 2009
2
Key Messages

• These meetings are preliminary informal
  discussions related to transmission rates.
• All new information shared is pre-decisional and
  not indicative of any particular rate case
  outcome
• Please feel free to ask questions and provide
  input as we move through these materials.

3
Meeting Objectives

• Discuss the high level approach to the cost of
  service analysis for transmission services.
• Demonstrate the established bases for segmenting
  the transmission revenue requirement.
• Discuss revenue requirement elements that have
  been altered or added since the last full rate
  case.
• Discuss the parking lot of customer issues and
  follow-up from the Sept. 9th customer meeting
  related to transmission, ancillary and control
  area service rates.

4
Transmission Parking Lot Protocols

• BPA will identify if the issue is within the
  scope of the rate case. If out of scope, BPA
  will point customers to the appropriate forum, if
  known.
• Pending written consent from the customer, BPA
  will post customer comments related to
  transmission rates on the corporate rates
  website.
• Transmission Account Executives will remain the
  first line of communication for customers.

5
Follow-up from Segmentation Meeting on Sept. 9th

• Update magnitude of investment to include
  Ancillary Services (see Appendix for details).
• Post facility names of unsold utility delivery
  substations.
• Clarify accounting and cash treatment of BPA
  owned and operated projects that are customer
  financed (see slides 27-28 from Sept. 9th
  handout).
• Discuss the OM ratios for each segment and how
  they are applied to the revenue requirement (see
  slide 16 of Sept. 9th handout).
• Explain the difference in OM cost allocations
  (see lines 2,4 on slide 48 of Sept. 9th handout).
• Clarify how overhead costs are accounted for with
  segmentation methodology (eg. contractor staff).
• Discuss customer issues parking lot for TR-12
  rate case.

6
What are the Rate Making Principles for
Transmission?

• Full and timely cost recovery.
• Lowest possible rates consistent with sound
  business principles.
• Cost causationfairly allocate costs to customers
  based on proportionate use.
• Statutory requirement of equitable allocation.
• Simplicity, understandability, public acceptance,
  and feasibility of application.
• Avoidance of rate shock and rate stability from
  rate period to rate period (eg. magnitude of
  rates and rate design).

Note Principles are adapted from James Bonbright
Principles of Public Utility Rates, 1968.
7
Study Background

• The last published segmented transmission Revenue
  Requirement Study was in the 2002 rate case.
• Unless otherwise noted, examples used in this
  presentation are for FY 2002 from Chapter 2 of
  the 2002 Final Revenue Requirement Study
  Documentation, TR-02-FS-BPA-01A.
• Unless otherwise noted, all numbers are in
  thousands.
• This presentation assumes a basic understanding
  of how BPA develops its revenue requirement
  study. For additional information on the study,
  see the TR-10 study at http//www.bpa.gov/corpor
  ate/ratecase/2008/2010_BPA_Rate_Case/tr-10.cfm

8
You are here
9
What is the Revenue Requirement Study?

• The Study identifies costs to be recovered over
  the rate period on both an accrual and cash
  basis. It includes forecasts of
• Program-level expenses
• Business units allocation of corporate expenses
• Depreciation
• Non-Federal debt service and other repayment
  obligations
• Federal Interest and Amortization as calculated
  in the Repayment Study
• Minimum Required Net Revenues (MRNR), if needed
  to ensure cost recovery on a cash basis
• Planned Net Revenues for Risk (PNRR), if needed
  to ensure the Treasury Payment Probability test
  is met
• The Study demonstrates cost recovery over the
  rate period on both an accrual and cash basis.
• Current Revenue Test Are revenues at current
  rates sufficient to cover the costs that must be
  recovered?
• Revised Revenue Test Are revenues at proposed
  rates sufficient to cover the costs that must be
  recovered?
• The Study demonstrates that revenues are
  sufficient to recover the Federal investment over
  a reasonable number of years per the Power Act
  and DOE Order RA 6120.2.

10
Transmission Revenue Requirement for FY 2002
11
Segmented Revenue Requirement for FY 2002
12
(No Transcript)
13
Segmentation of Operations Maintenance
Step 1, Direct Assignment The costs for
generation inputs to ancillary services, COE and
Reclamation transmission, ancillary services OM,
leases, GTAs (non-Federal transmission
arrangements), and remedial action schemes (RAS)
are assigned to segments and ancillary services
as appropriate. The bases for these assignments
are made by staff supporting the respective
areas, except for COE and Reclamation costs. COE
and Reclamation costs are segmented using the
same method seen in the 2002 power rate, which is
based on average gross investment. Depreciation
is calculated from the Network and Utility
Delivery investment, and interest is based on
average net plant.
A
B
C
D
E
F
G
H
SOUTHERN
EASTERN
UTILITY
ANCILLARY
FY 2002
TOTAL
GI
NETWORK
INTERTIE
INTERTIE
DELIVERY
DSI
SERVICES
1
DIRECT ASSIGNMENT
2
GENERATION INPUTS
71,664
71,664
3
COE/BOR TRANSMISSION
3,701
3,478
223
4
STABILITY RESERVES
0
5
ANCILLARY SERVICES OM
20,643
20,643
6
LEASES
5,267
5,188
79
7
GTAs
2,000
2,000
8
TOTAL OM DIRECT ASSIGN
27,910
0
7,188
0
0
79
0
20,643
Note Line 8 is only the sum of the
non-interbusiness line elements, lines 4 through
7.
14
OM continued
Step 2, Three-Year Averages of Historical Data
The transmission system operations (minus the
directly-assigned amount for ancillary services)
and maintenance and environmental remediation
programs are divided between lines and
substations according to a 3-year historical
average of that split. Costs are then separately
segmented for lines and substations based on each
segments share of the respective 3-year total
averages of historical OM.
A
B
C
D
E
F
G
H
EASTERN
UTILITY
ANCILLARY
SOUTHERN
FY 2002
TOTAL
GI
NETWORK
INTERTIE
INTERTIE
DELIVERY
DSI
SERVICES
9
3-YR AVG OM LINES
58,744
548
53,245
4,023
924
4
0
10
3-YR AVG OM SUBS
43,866
751
28,828
10,145
215
2,504
1,423
11
TOTAL 3-YR AVG
102,610
12
SYS OP, SYS MNT, ENV
86,753
13
DIRECT LINES OM
49,666
463
45,018
3,401
781
3
14
DIRECT SUBS OM
37,087
635
24,373
8,577
182
2,117
1,203
15
TOTAL DIRECT TRANS OM
86,753
1,098
69,391
11,978
963
2,120
1,203
16
TOTAL DIRECT OM
107,396
1,098
69,391
11,978
963
2,120
1,203
20,643
15
OM continued
Step 3, Sum of Previously Segmented Non-Payment
Related OM The classification of ancillary
services OM in Step 1 and transmission OM in
Step 2 are summed in order to provide the pro
rata basis for the segmentation of all remaining
OM costs. Station service is segmented by each
segments share of the total 3-year historical
averages of OM for substations.
A
B
C
D
E
F
G
H
SOUTHERN
EASTERN
UTILITY
ANCILLARY
FY 2002
TOTAL
GI
NETWORK
INTERTIE
INTERTIE
DELIVERY
DSI
SERVICES
16
TOTAL DIRECT OM
107,396
1,098
69,391
11,978
963
2,120
1,203
20,643
17
OVERHEAD CATEGORIES
121,023
1,237
78,196
13,498
1,085
2,389
1,356
23,262
18
TOTAL OM
235,686
2,335
154,775
25,476
2,048
4,588
2,559
43,905
19
STATION SERVICE
1,724
30
1,133
399
8
98
56
20
RAS
231
0
0
231
0
0
0
21
TOTAL INTERBUSINESS LINE
77,320
30
4,611
630
8
321
56
71,664
16
Segmentation of Depreciation
Step 1 BPA transmission depreciation is
calculated for each segment and ancillary service
from the gross investment.
17
Depreciation continued
Step 2 Transmission depreciation for control
equipment and communications equipment is pro
rated to the segments based on their depreciation
expense.
A
B
C
D
E
F
G
H
SOUTHERN
EASTERN
UTILITY
ANCILLARY
FY 2002
TOTAL
GI
NETWORK
INTERTIE
INTERTIE
DELIVERY
DSI
SERVICES
6
DEPRECIATION
117,032
1,780
88,919
19,543
3,010
1,982
1,798
21,304
7
percent
100
1.52
75.98
16.70
2.57
1.69
1.54
8
TX GP DEPRECIATION
24,262
369
18,434
4,051
624
411
373
Step 3 The remaining general plant depreciation
is prorated to the segments and ancillary
services based on the total of the above steps.
A
B
C
D
E
F
G
H
SOUTHERN
EASTERN
UTILITY
ANCILLARY
FY 2002
TOTAL
GI
NETWORK
INTERTIE
INTERTIE
DELIVERY
DSI
SERVICES
8
TX GP DEPRECIATION
24,262
369
18,434
4,051
624
411
373
9
subtotal
162,598
2,149
107,353
23,594
3,634
2,393
2,171
21,304
10
percent
100
1.32
66.02
14.51
2.23
1.47
1.34
13.10
11
REMAINING GP DEPR
19,136
253
12,633
2,777
428
282
256
2,507
12
TOTAL DEPR
181,734
2,402
119,986
26,371
4,062
2,675
2,427
23,811
18
Segmentation of Net Interest and Planned Net
Revenues
Step 1 The net investment base for each segment
is calculated. The Southern Intertie net plant
is adjusted to remove the balance of the unearned
revenues associated with non-Federal capacity
ownership. Similarly, the unearned revenue
balance associated with prepaid fiber optic
leases is segmented pro rata based on the
disposition of communications plant in each
segment to reduce net plant.
A
B
C
E
F
G
H
D
GENERATION
SOUTHERN
EASTERN
UTILITY
ANCILLARY
TOTAL
FY 2002
INTEGRATION
NETWORK
INTERTIE
INTERTIE
DELIVERY
DSI
SERVICES
1
NET TRANSMISSION PLANT
2,496,199
40,836
1,854,797
448,175
65,495
46,215
40,681
2
PERCENT
100
1.64
74.30
17.95
2.62
1.85
1.63
3
TRANS GP 353 and 397
332,756
5,444
247,254
59,744
8,731
6,161
5,423
4
SUBTOTAL PLANT
3,033,874
46,280
2,102,051
507,919
74,226
52,376
46,104
204,918
5
PERCENT
100
1.53
69.29
16.74
2.45
1.73
1.52
6.75
6
REMAINING GEN PLANT
243,635
3,717
168,805
40,788
5,961
4,206
3,702
16,456
7
ACC REV BAL ADJ - Fiber
(12,599)
(116)
(5,258)
(1,270)
(186)
(131)
(115)
(5,523)
8
ACC REV BAL ADJ - 3AC
(128,851)
(128,851)
9
INVESTMENT BASE
3,136,059
49,881
2,265,598
418,586
80,001
56,451
49,691
215,851
19
Segmentation of Net Interest and Planned Net
Revenues
Step 2 The transmission Net Interest expense,
the Planned Net Revenues, Minimum Required Net
Revenues (MRNR), and Planned Net Revenues for
Risk (PNRR) are prorated to the segments and
ancillary services based on the average net plant
investment in those areas. As part of this
calculation, interest credits for the sale of
facilities in Utility and DSI Delivery segments
are applied directly to those segments prior to
the segmentation of the remainder of net interest
expense.
A
B
C
D
E
F
G
H
SOUTHERN
EASTERN
UTILITY
ANCILLARY
FY 2002
TOTAL
GI
NETWORK
INTERTIE
INTERTIE
DELIVERY
DSI
SERVICES
1
INVESTMENT BASE
3,136,059
49,881
2,265,598
418,586
80,001
56,451
49,691
215,851
2
percent
100
1.59
72.24
13.35
2.55
1.80
1.58
6.88
3
Interest Credit from Facilities Sales
(752)
(376)
(376)
4
NET INTEREST
177,060
2,816
127,914
23,633
4,517
3,187
2,806
12,187
5
NET REVENUES
0
0
0
0
0
0
0
0
Terminology

• Planned Net Revenue for Risk (PNRR) A component
  of the revenue requirement that is added to
  annual expenses. PNRR adds to cash flows so that
  financial reserves are sufficient to mitigate
  short-run volatility in costs and revenues and
  achieve the TP goal. No PNRR was required to
  meet the TR-10 TPP standard.
• Minimum Required Net Revenues (MRNR) Result
  from an analysis of the Statement of Cash Flows.
  MRNR may be necessary to ensure that the revenue
  requirement is sufficient to cover all cash
  requirements, including annual amortization of
  the Federal investment as determined in the
  transmission repayment studies.

20
Whats Changed in Transmission Revenue
Requirements Since the 2002 Transmission Rate
Case?

• Debt Service Reassignment (DSR)
• This is a debt swap from using Debt Optimization
  proceeds from Power to repay Transmission
  Treasury bonds to restore borrowing authority.
  Energy Northwest debt was refinanced (extended),
  providing the source of funds to retire
  Transmission debt. As a result, Transmission
  assumes the responsibility to recover the
  refinanced debt.
• As a debt swap, it is treated just like the
  Treasury bonds that financed Transmission
  projects initially, so no changes are required.
• It can be segmented without differentiation as
  part of Transmission net interest and Minimum
  Required Net Revenues (for the principal).

21
Changes continued

• Lease Financing
• To stretch available borrowing authority, BPA
  entered into agreements with a financing entity
  (NIFC) to fund discrete transmission projects.
  The Schultz-Wautoma project was the first.
• The entity owns the facilities and leases them to
  BPA with the expectation that BPA will assume
  ownership after the financing costs are repaid.
• As such, the investment is included in BPA's
  plant-in-service and is reflected in the
  Segmentation Study.
• The associated interest is now included in
  Transmission net interest and can be segmented
  accordingly (as can the principal as factored
  into MRNR when it comes due in later years).

22
Changes continued

• Regulatory Assets (Spacer Dampers and Non-Wires
  Solutions)
• The Spacer Damper Program was created to make an
  asset out of what otherwise would have been an
  extraordinary maintenance expense (accelerated
  replacement of defective equipment). It spreads
  the cost recovery burden over the life of the
  equipment (30 years) rather than affecting
  transmission rates as an annual expense over a
  5-8 year period. Spacer dampers don't cost
  enough to qualify as capital investment. We will
  need to associate costs with segments (most
  likely Network).
• Spacer Dampers have been funded by Treasury bonds
  through FY 2009, but they are switching to the
  lease-financing program. New investments that are
  lease financed will not be regulatory assets, and
  instead are included in the plant-in-service of
  the particular lines. That part will be more
  straightforward.
• The Non-wires Solutions program (although it was
  forecast to begin during the 2008-2009 rate
  period, nothing has happened yet) are basically
  demand side management actions to reduce the need
  for new transmission lines. It is unclear about
  the future of this program.

23
Changes continued

• Customer Financed Projects and Resulting
  Transmission Revenue Credits
• This category currently consists of Large
  Generator Interconnection Agreement (LGIA)
  projects. However, other construction projects
  that use the LGIA model would face the same
  issues.
• There are 2 aspects to this (a) interest
  accrued on customer deposits with accompanying
  AFUDC during construction of the associated
  projects, and (b) the pay back of the deposits
  and interest to those customers through credits
  against charges for transmission service.
• Both aspects are non-cash elements and effect the
  revenue requirement in different ways. The
  interest is now (as of FY 2009) a component of
  net interest expense, combined with the interest
  from Treasury bonds, congressional
  appropriations, DSR and lease financing
  transactions. One treatment would be to segment
  the components separately and assign them
  directly to the Network. The associated
  investment would need to be identified separately
  in the Segmentation Study and excluded from the
  Network investment base.
• The revenues must be taken into account because
  they provide no cash for demonstrating cost
  recovery. Minimum Required Net Revenues, the
  adder to the revenue requirement to cover any
  cash requirements not covered by non-cash
  expenses, is increased by the amount of the
  credited revenues. One thought is that an amount
  of the MRNR equivalent to the credited revenues
  net of the associated interest would be assigned
  directly to the Network, before segmenting the
  remainder. As above, the facilities so funded
  would be excluded from the segmented investment
  base that is used to allocate the other interest
  expense elements and MRNR, but we would still
  need to calculate depreciation on
  the investment.

24
(No Transcript)
25
Allocating MRNR Associated with Customer Financed
Transmission Credit Projects
Here, an amount of the MRNR equivalent to the
credited revenues (net of the associated
expenses) would be assigned directly to the
Network, before segmenting the remainder. The
facilities so funded should be excluded from the
segmented investment base that is used to
allocate all other interest and remaining MRNR,
but we would still need to calculate depreciation
on the investment. This treatment would pertain
to any segment with associated transmission
credit projects.
26
Changes continued

• Use of TS Cash Reserves to Reduce Expenses
  Recovered Through Rates
• In the TR-10 revenue requirement, 40 million of
  TS cash reserves were applied to offset a portion
  of IPR-approved spending levels in expense
  programs, so that revenues from the settled rates
  would only have to recover the net amount.
• This use of cash reserves was included in the
  revenue requirement income statement as a
  negative value in each year under Other Income,
  Expenses Adjustments.
• If this approach was incorporated into rate
  development, it would seem to follow that the
  adjustment be segmented based on the segmentation
  of all other OM expenses.

27
Parking Lot Issues

• Whether or not to establish a short distance
  discount for the Southern Intertie?
• A future Transmission Rates Workshop to be
  scheduled.
• Whether or not to establish a formula for
  incremental cost rates for NOS plan-of-service
  that do not meet the criteria to move forward at
  embedded cost rates? If so, how and when should
  discussions take place to develop the structure
  and elements of the public process?
• Transmission Services will discuss this issue at
  the end of the November 4, 2009 customer meeting
  on Rate Design and Risk Analysis.
• Whether or not to offer to replace customer
  served load to preserve some benefit previously
  received through CSL credits?
• A future Transmission Rates Workshop to be
  scheduled.
• Discuss potential rate impact of utility delivery
  segment.
• A future Transmission Rates Workshop to be
  scheduled.

28
For More Information

• Check the agency calendar for future
  transmission, ancillary or control area service
  rates or business practice meetings that address
  the implementation of rates at
  http//www.bpa.gov/corporate/public_affairs/calend
  ar/
• Additional rates backgrounds is available online
  at http//www.bpa.gov/corporate/ratecase/2008/201
  0_BPA_Rate_Case/meetings.cfm
• Record of Decision (TR-10-A-02)
• Transmission Revenue Requirement Study
  (TR-10-FS-BPA-01)
• Transmission Revenue Requirement Study
  Documentation (TR-10-FS-BPA-01A)
• Statements A-F (TR-10-FS-BPA-03)

29
Appendix These slides are provided as follow-up
to clarify and/or provide information requested
by customers at the September 9, 2009 meeting on
Segmentation Analysis.
30
Traditional Utility Cost of Service Diagram
Predecisional/For Discussion Purposes Only
31
Unsold Utility Delivery Substations
32
Unsold Utility Delivery Substations continued
33
Whats the Magnitude of Investment?As of
09/30/1998
Note Cross reference to slide 43 in the
Segmentation Analysis Presentation dated 9/9/09
posted to Corporate Rates website. Due to
rounding, some percentages may not total 100.
1\ Unlike the other segments, this segment
consists entirely of general plant and does not
include lines and substations.
34
Whats the Magnitude of Investment? As of
09/30/2007
Note Cross reference to slide 44 in the
Segmentation Analysis Presentation dated 9/9/09
posted to Corporate Rates website. Due to
rounding, some percentages may not total 100.
1\ Unlike the other segments, this segment
consists entirely of general plant and does not
include lines and substations.
35
What are Some of the Significant Changes in Data
Between 2002-2007?

• The size of the Network segment, both absolutely
  and relative to the other segments, has grown.
• The size of the Delivery segments, both
  absolutely and relative to the other segments,
  has contracted.

Note Cross reference to slide 45 in the
Segmentation Analysis Presentation dated 9/9/09
posted to Corporate Rates website
36
Whats the FCRTS Investment?As of 09/30/2007
Note Cross reference to slide 52 in the
Segmentation Analysis Presentation dated 9/9/09
posted to Corporate Rates website. Due to
rounding, some percentages may not total 100.
1\ Unlike the other segments, this segment
consists entirely of general plant and does not
include lines and substations.