AEP PRESENTATION
TO SPP MULTI-OWNER
COMPENSATION
TASK FORCE
Presented July 8, 2004
Dallas, Texas
Purpose of SPP MOCTF
What does the MOCTF actually need to do?
 FERC’s SPP RTO Orders Feb. 10 and July 2, 2004
only direct SPP to develop a timetable for resolution
of the Compensation for Customer Owned Facilities.
 “..we note that SPP and stakeholders are currently in
the process of developing a single definition of
transmission. …this issue will take time”
 “We will direct SPP to submit the timetable as
prescribed in the February 10 Order.”
Source: SPP, 108 FERC ¶ 61,003 at P 65 and P 80 (2004).
22
AEP Position Re:
Inclusion of TDU Facilities in Rates
TDU facilities that are found to be transmission
facilities, e.g., are integrated with the regional
transmission system, providing benefits in
terms capability and reliability to other
customers, should qualify for cost recovery,
from the customers who use and benefit from
them, through the SPP regional OATT.
33
Introduction of Issues
Historically, the fundamental principle in utility rate
design has been that customers should bear the costs of
facilities that are planned for their benefit, and used to
provide them utility service(s).
To the extent that other users provide revenue for
incidental use, the costs borne by “planned service
customers” are reduced.
AEP’s rates to “planned service” customers, including
ETEC, reflect credits for revenues received from others
for incidental service.
ETEC facilities were planned by ETEC to serve its REC
members, and FERC has found that they provide no
capability or reliability benefit to other AEP customers.
44
Review of FERC Orders
The Feb 10 SPP RTO Order
The Integration Analysis: Although Lafayette
criticized the Section 30.9 “integration” standard, the
Commission noted that “integration” requirement with
approval, and specifically referenced the Initial Decision in
Consumers and the recent FP&L “credits” order.
Source: SPP, 106 FERC ¶ 61,110 at P 114 (2004).
The Seven Factor “Transmission” Test: The
Commission pointed to the Wolverine decision, which applied
the Seven Factor Test to determine whether facilities of
multiple parties should be included in a single MISO
transmission rate zone.
Source: SPP, 106 FERC ¶ 61,110 at P 115 (2004).
55
Review of FERC Orders
Seven Factor “Transmission” Test
In Midwest ISO, the Commission applied the Seven Factor
Test to determine whether facilities owned by Wolverine were
eligible for consideration in a multiple-owner rate zone:
1.
2.
3.
4.
Local distribution facilities are normally in close proximity to retail customers.
Local distribution facilities are primarily radial in character.
Power flows into local distribution systems; it rarely, if ever, flows out.
When power enters a local distribution system, it is not re-consigned or
transported on to some other market.
5. Power entering a local distribution system is consumed in a comparatively
restricted geographical area.
6. Meters are based at the transmission/local distribution interface to measure
flows into the local distribution system.
7. Local distribution systems will be of reduced voltage.
Source: Midwest Independent Transmission System Operator, 101 FERC ¶ 61,004 (2002) and 106 FERC ¶ 61,219
(2004); Order No. 888, FERC Stats. & Regs. ¶ 31,036 at 31,783-84 (1996) (subsequent history omitted).
66
Review of FERC Orders
The Integration Analysis
To receive credits, the customer must demonstrate:
 That the facilities at issue are integrated into the plans and
operations of the transmission provider to serve its customers.
 That the transmission provider can and does use the facilities
to provide transmission service to itself or other customers.
 The facilities provide additional benefits to the transmission
grid in terms of capability and reliability, and are relied upon
for coordinated operation of the grid.
Source: Consumers Energy Co., 86 FERC ¶ 63,004 at 65,016 (1999), aff’d,
98 FERC ¶ 61,333 (2002).
77
Review of FERC Orders
The Integration Analysis (Cont.)
Interconnection “alone” is not enough:
 The fact that the facilities serve a transmission function on the
customer’s side of the interconnection point is not enough to
prove integration.
 The fact that a facility offers a parallel path and is subject to
parallel flows does not require a conclusion that the line
operates as part of an integrated network.
 Unnecessary redundancy does not qualify facilities for credits.
Source: Consumers Energy Co., 86 FERC ¶ 63,004 at 65,016 (1999), aff’d,
98 FERC ¶ 61,333 (2002).
88
Review of FERC Orders
Integration Analysis (Cont.)
Incidental Loop Flow:
“FMPA argues . . . that the [looped] … line
provides an alternate transmission path
and increases reliability on the Florida
Power system. The fact that the … line
constitutes a parallel path and is subject to
occasional loop flow does not, in and of
itself, compel a conclusion that the line
now operates as part of the Florida Power
integrated transmission network.”
(FERC Order in FMPA II), emphasis added
99
Review of FERC Orders
The Mansfield Integration Test
Five Tests for Facility Integration:
 Whether the facilities are radial, or loop back into the transmission
system
 Whether energy flows only in one direction over the facilities, or in
both directions
 Whether the transmission provider furnishes transmission service to
itself or other transmission customers over the facilities
 Whether the facilities provide benefits to the transmission grid in
terms of capability or reliability, and whether the facilities can be
relied upon for the coordinated operation of the grid
 Whether an outage of the facility would affect the transmission system
Source: Mansfield Municipal Electric Dept. v. New England Power Co.,
94 FERC ¶ 63,023 at 65,170, aff’d, 97 FERC ¶ 61,134 at 61,613-14 (2001).
10 10
Review of FERC Orders
Re: Capability & Reliability Benefits
In order to determine whether facilities provide additional
benefits to the transmission grid in terms of capability and
reliability, the proper method is to look at the system as a
whole in a base case load flow, and then compare this base
case to a change case in which the facilities are not
connected to the system.
“Entergy performed a base case load flow study of its
system under normal situations and contingency conditions.
Then Entergy, examined how those same base and
contingency case conditions would change if Entergy were
not connected to the customer systems in question. The
results showed that Entergy’s other wholesale and retail
customers would not be negatively affected if the customerowned facilities were not present.”
Source: Entergy Services, Inc., 85 FERC ¶ 61,163 at 61,649 (1998).
Emphasis added
11 11
Review of FERC Orders
The ETEC v. CSW Initial Decision
On October 29, 1999, in East Texas Electric Cooperative,
Inc. v. Central and South West Services, Inc., 89 FERC ¶
63,005 (1999), exceptions pending, a FERC
Administrative Law Judge ruled that the facilities of
ETEC are not integrated with the facilities of the AEP
operating companies under Section 30.9 of the AEP
OATT.
Because the "integration" of ETEC's facilities has been
squarely presented to the Commission, the Multi-Owner
Compensation Task Force need not address the
"integration" question with regard to ETEC's facilities
until after a final order is issued in ETEC v. CSW.
12 12
Review of FERC Orders
Other Statements on Integration
In Docket No. ER99-4392, FERC denied ETEX’s
claim that their facilities should constitute an SPP
pricing zone because their facilities “are used
solely to distribute power to their distribution
members, do not provide any benefits to SPP in
terms of additional capability and reliability, are
not relied upon for the coordinated operation of
the grid, and are not integrated with any SPP
transmission provider[.]” SPP, 98 FERC ¶ 61,038 (2002)
On appeal, the court upheld the use of the
“integration” standard, but remanded for further
evidence on whether the Texas Cooperatives
satisfied this integration standard.
13 13
Review of FERC Orders
Add’l. Statements on Integration
FERC explained to the court that the integration
standard involves “‘application of a fundamental
ratemaking principle: that cost responsibility should
match cost and benefit’ and ‘parties should not be
required to pay the costs of facilities or services
unless they actually receive some benefit from
them.’” ETEC v. FERC, 331 F.3d 131, 136 (D.C.Cir. 2003) (quoting FERC Brief at 2).
The court concluded that this integration standard
was consistent with the SPP OATT’s standard for
customer credits found in Section 30.9.
ETEC v. FERC, 331 F.3d at 137.
This court remand is pending before the FERC.
14 14
Function of ETEC’s Lines
The ETEX RECs are wholesale customers of (not
suppliers to) SWEPCO
Most ETEX REC lines are radial circuits
ETEC’s 138 kV line from Crockett Station tying to
Rayburn Country’s Mineola – Overton line at
Jacksonville Station, does not provide benefits in
terms of capability and reliability to other SWEPCO
customers.
 There is no generation connected to the line or behind any
of the delivery points along the line
 No SWEPCO lines connect into Jacksonville Station
15 15
Function of ETEC Lines
ETEC Crockett-Jacksonville Line
kV
138
MINEOLA
(SWEPCO)
RAY
BU
138 RN
kV
PIRKEY
(SWEPCO)
ETE
C
138
kV
JACKSONVILLE
(SWEPCO)
34
5
OVERTON
(SWEPCO)
ET
E
SW C
EP
CO
N
BUR
Y
A
R
kV
138
ETE
Loa C
ds
kV
kV
138
CROCKETT
(SWEPCO)
Grimes
(Entergy)
16 16
Function of ETEC’s Lines
Transmission Contingency Analysis
 NERC [n-1] contingency load flow analysis shows that SWEPCO
is not dependent upon the Crocket-Jacksonville 138 kV line to
meet transmission reliability criteria for other customers.
 The energy that flows from AEP into the ETEC 138 kV line at
Crockett Station rarely flows back to SWEPCO, and even then
SWEPCO’s other customers would not be harmed if such flow
was prevented.
Many of ETEC’s lines, are “Economic Upgrades,”
as that term is used in SPP Participant Funding
discussions, that were built to move their load
from ERCOT to SPP to obtain the economic
benefit of lower energy costs in SPP.
17 17
Cost Shifts with inclusion of
ETEX Facilities in AEP Zone
ETEX claims annual revenue requirement (ARR) of $8.9
million for facilities > 60 kV in SPP.
Impact on AEP Network Transmission customers sharing
the present AEP SPP TCOS by 12 CP load ratios.
Cust.
AEP
TCOS
ETEX
ARR
Cost
Shift
AEP
NTS
NTS
%
NTS
80.6
8.1
8.1
88.7
10.1
ETEX
8.1
0.8
(8.1)
0.0
(100)
Total
88.7
8.9
----
88.7
----
**
18 18
AEP Position Re:
Inclusion of TDU Facilities in Rates
TDU facilities that are found to be transmission
facilities, e.g., are integrated with the regional
transmission system, providing benefits in
terms capability and reliability to other
customers, should qualify for cost recovery,
from the customers who use and benefit from
them, through the SPP regional OATT.
19 19
Questions
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