12-2500-19336-2
E-017/GR-07-1178
STATE OF
OFFICE OF
ADMINISTRATIVE HEARINGS
FOR THE
PUBLIC UTILITIES COMMISSION
|
In the Matter of the Application of Otter Tail Corporation d/b/a/
Otter Tail Power Company for Authority to Increase Rates for Electric Utility
Service in |
FINDINGS OF FACT, CONCLUSIONS AND RECOMMENDATION |
The above-entitled matter came on for
evidentiary hearing before Administrative Law Judge
The parties to this proceeding are: Otter Tail Corporation d/b/a Otter Tail Power
Company (“OTP” or the “Company”); the Minnesota Department of Commerce/Office
of Energy Security (the “Department”);[1]
the Minnesota Office of Attorney General -- Residential Utilities Division
(“OAG”); Enbridge Energy Limited Partnership and Enbridge Energy Company, Inc.
(“Enbridge”); the Minnesota Chamber of Commerce (the “MCC”); AG Processing,
Inc. (“AG Processing”); and Jonathan Drews who filed Direct Testimony, but has
not otherwise participated in these proceedings. These intervenors, collectively, sponsored
prefiled written testimony of 15 witnesses.
Appearances were made by the
following: For OTP, Bruce Gerhardson,
Associate General Counsel, Otter Tail Power Company,
Notice is hereby given that, pursuant to
Minn. Stat. § 14.61, and the Rules of Practice of the Minnesota Public
Utilities Commission (the “Commission”) and the Office of Administrative
Hearings, exceptions to this Report, if any, by any party adversely affected
must be filed within 15 days of the mailing date hereof with the Executive
Secretary, Minnesota Public Utilities Commission, Metro Square Building, Suite
350, 121 7th Place East, St. Paul, Minnesota 55101-2147. Exceptions must be specific and stated and
numbered separately. Proposed Findings
of Fact, Conclusions of Law and Order should be included, and copies thereof
shall be served upon all parties. Oral
argument before a majority of the Commission will be permitted to all parties
adversely affected by the Administrative Law Judge’s recommendation who request
such argument with their filed exceptions or reply. Exceptions should be e-filed with the
Commission.
The Commission will make the final
determination of the matter after the expiration of the period for filing
exceptions as set forth above, or after oral argument, if such is requested and
had in the matter.
Further notice is hereby given that the
Commission may, at its own discretion, accept or reject the Administrative Law
Judge’s recommendation and that said recommendation has no legal effect unless
expressly adopted by the Commission as its final order.
A.
Jurisdictional-Procedural
Background.
4.
On February 29,
2008, the Company, the Department, and the MCC filed Rebuttal Testimony.
B.
Summary of
Public Comments.
6.
Public hearings
were held on February 5, 2008, at the Bemidji City Hall in Bemidji (two members
of the public spoke); February 6, 2008, 1:00 p.m., at the Morris City Hall in
Morris (five members of the public spoke); February 6, 2008, 7:00 p.m., at
the Fergus Falls City Council Chambers in Fergus Falls (six members of the
public spoke); and February 7, 2008, at the Youngquist Auditorium of the
University of Minnesota in Crookston (one member of the public spoke). A total of 14 members of the public
participated in the public hearings by speaking. Comments included: praise for the Company’s commitment to
economic development in rural
C.
Description of the
Company.
7.
Otter Tail
Corporation is a
[I]n the exercise of the statutorily
imposed duty to determine whether the inclusion of the item generating the
claimed cost is appropriate, or whether the ratepayers or the shareholders
should sustain the burden generated by the claimed cost, the MPUC acts in both
a quasi-judicial and a partially legislative capacity. To state it differently, in evaluating the
case, the accent is more on the inferences and conclusions to be drawn from the
basic facts (i.e., the amount of the claimed costs) rather than on the
reliability of the facts themselves. Thus, by merely showing that it has
incurred, or may hypothetically incur, expenses, the utility does not
necessarily meet its burden of demonstrating it is just and reasonable that the
ratepayers bear the costs of those expenses.[2]
In that
same case, the Minnesota Supreme Court also stated that:
In
evaluating the validity of a rate increase application, the Commission should
apply the classic burden of proof analysis employed in civil cases in
determining whether the utility has established the amount of a claimed cost as
a judicial fact.[3]
10.
In civil cases,
the burden of proof has two separate meanings.
1. The duty of creating an affirmative belief on
the part of the tribunal in the existence of the fact or facts in issue, or
2. The duty of introducing evidence at a
particular stage of a trial -- of going forward with the evidence.[4]
A.
The
Jurisdictional Cost Allocation Issue.
13.
As noted by the
Commission in a prior order, "Rates for OTP have been established in the
past as if the Company operates one system covering portions of
14.
Enbridge and MCC
propose to allocate 115 and higher voltage costs based on demand, but the cost
of 69 kV and 41.6 kV facilities based on mileage. The Enbridge/MCC adjustment would reduce the
15.
The Department
proposes to allocate the cost of 69 kV and higher voltage based on demand, but
the 41.6 kV facilities based on mileage. The Department’s adjustment would
reduce the
18.
The Commission
addressed the asset separation issue in its Boundary
Order, adopted in 2000.[9] The Boundary
Order adopted Guidelines proposed by an industry group, and directed that
these Guidelines apply to: “competitive proceedings, cost separation dockets,
rate cases, and valuations for asset transfers.”[10] The Commission noted that “these issues are
not of slight or transitory significance” and went on to state:
Given the
centrality of these issues, and the broad agreement among industry participants
on the proposed guidelines for addressing these issues, the Commission will
approve the proposed guidelines. The
guidelines have the advantage of providing a uniform, state-wide framework for
analyzing asset separation issues, while providing individualized application
to various utilities. The guidelines
shall be used wherever issues of identifying the assets involved in generation,
transmission or distribution arise ….
The Commission adopts the … guidelines for the purpose of determining
the functional boundaries between the transmission and generation functions,
and between the transmission and distribution functions. The Commission directs the parties to use the
guidelines and appendices in all future proceedings involving unbundling and
other relevant proceedings.[11]
19.
The Boundary Order distinguished between
generation, transmission, and distribution.
There is no intermediary subtransmission category created in the Boundary Order.[12]
1.
Determining
Whether 41.6 kV And 69 kV Are Transmission Using The Boundary Order.
20.
The Boundary Order sets out eight Minnesota
Boundary Guidelines. OTP initially
performed a system-wide analysis using the Boundary Guidelines and presented
its results in Mr. Rogelstad’s Rebuttal testimony.[13] That analysis focused on Guideline 1, which
addresses transmission lines.
21.
Guideline 1, as
set out in the Boundary Order, states:
Lines with
voltage of more than 50 kV are considered transmission assets unless
demonstrated to be distribution assets after application of the relevant
factors. Lines with voltage of 50 kV or
less are distribution assets unless demonstrated to be transmission assets
after application of relevant factors.
See Appendix A regarding “relevant factors.”
23.
FERC FACTOR 1 states that
local distribution facilities are normally in close proximity to retail
customers. OTP’s 41.6 kV and 69 kV
facilities are not in close proximity to retail customers. The closest the transmission facilities come
to retail customers is at the substations where the transmission delivers power
to be stepped down for retail use.[14] Application of this factor to OTP’s 41.6 kV
and 69 kV facilities supports a finding that the facilities perform a
transmission function.
24.
FERC FACTOR 2 asks
whether the facilities are primarily radial in nature. Facilities that are radial in nature do not
have the ability to connect into or be looped to other transmission facilities
and are more likely to be distribution.
Radial lines can also be transmission if they perform a transmission
function.[15] A radial line terminates to a substation
where the energy is used and is not capable of operating in a looped fashion.[16] OTP’s 41.6 kV and 69 kV transmission
facilities have been planned and designed with looped capability and have the
ability to transfer energy throughout the geographic region served by OTP and
its interconnected neighbors.[17] OTP removed all radial lines (two percent of
its lines were radial) and OTP’s facilities do not terminate to a substation.[18]
25.
MCC maintains
that because OTP operates portions of its facilities normally open, all of the
facilities are radial in nature.[19] Operating a line normally open means that
somewhere in the transmission line a switch is opened so that power flows into
the line from both ends rather than through the line. While open, the line separately serves the
communities on each side of the open switch and cannot instantaneously support
other transmission lines if there is a fault.
By opening the lines, OTP improves reliability for communities served
off the line. Mr. Schedin agreed that
this practice enhances reliability for customers served by the line.[20]
26.
OTP noted that
it closes these normally open facilities on a daily basis, as maintenance is
required and whenever a need exists to support other transmission demands during
faults.[21] Mr. Sherner opined that the 41.6 kV
facilities cannot be operated normally closed because the heavy loading on the
overlay of high voltage transmission would result in 41.6 kV facilities
overloads.[22] Mr. Rogelstad disagreed, noting that OTP
operates the lines closed in its day-to-day operations,[23] and further
stated that “OTP has installed sophisticated relaying systems that protect the
lines to ensure that overloads will not occur.”[24]
28.
FERC FACTOR 3: Does power flow into the facilities and rarely,
if ever, flow out? In distribution
networks, the power is consumed and, therefore, power does not flow out. OTP has shown that it’s 41.6 kV and 69 kV
facilities were planned and designed to have power flow into, through, and
out. Most of OTP’s generation facilities
are located in North and
29.
Mr. Schedin maintained
that OTP’s practice of operating portions of its lines normally open means that
power normally flows in and rarely, if ever, flows out and is therefore
distribution.[27] In response, OTP stated that all of OTP’s
lines are in a looped configuration,[28] most serve
multiple loads,[29] many serve
loads of other utilities,[30] (including
GRE, which serves no distribution function), none serve a single load by
terminating at a distribution substation,[31] and they
are capable of supporting other transmission.[32] Additionally, OTP closes these lines on a
daily basis.[33] OTP also operates approximately 20 percent
(184.2 miles) of its higher voltage 115 kV lines normally. No one has maintained that OTP’s 115 kV lines
are distribution, not transmission.
31.
FERC FACTOR 4: When power enters the facilities is it ever
reconsigned or transported to some other market? OTP jointly developed the integrated
transmission system with its neighboring utilities, designing the system to
transfer power for multiple utilities over the 41.6 kV and 69 kV facilities and
to facilitate the Midcontinent Area Power Pool (“MAPP”) and later the MISO
Energy Market. A merchant wind generator
has recently signed an interconnection agreement to interconnect with OTP’s
41.6 kV facilities near
32.
FERC FACTOR 5: Is the power that enters the facilities
consumed in a comparatively restricted geographic area? OTP’s 41.6 kV and 69 kV facilities are part of
an integrated transmission network that transfers power across OTP’s 50,000
square mile service territory. OTP
inputs power on the transmission system, including the 41.6 kV and 69 kV
facilities, in North and
33.
Mr. Rogelstad
provided a map of the Otter Tail service area with only OTP’s 115 kV and above
depicted. OTP noted that it also uses
other utilities’ transmission facilities.
OTP’s ability to use other utilities’ facilities is conditioned on
reciprocating by allowing those other utilities to use OTP’s facilities,
including OTP’s 41.6 kV and 69 kV lines.
OTP would be unable to provide power throughout its service territory
without the use of approximately 3,900 miles of 41.6 kV and 200 miles of 69 kV
lines and the reciprocal access those facilities provide to the transmission facilities
of other utilities.[39] Application of FERC factor 5 to OTP’s 41.6 kV
and 69 kV facilities supports a finding that the facilities perform a
transmission function.
34.
FERC FACTOR 6: Where are the meters that measure the flow
into the local distribution system located?
All of Otter Tail’s transmission partners -- GRE, MCP, Missouri River
Energy Services (“MRES”), etc. -- have metering on the distribution side of the
distribution substation transformer.
These substation transformers typically step down 41.6 kV to 12.5 kV
with the meter on the 12.5 kV side of the transformer.[40] Application of FERC factor 6 to OTP’s 41.6 kV
and 69 kV facilities supports a finding that the facilities perform a
transmission function.
35.
FERC FACTOR 7: Are these facilities of “reduced
voltage.” In reference to FERC Factor 7,
FERC said, “The [FERC] has analyzed utilities’ filings required by the [FERC]’s
regulations. These filings are made on
FERC Form No. 1. While there is no
uniform breakpoint between transmission and distribution, it appears that
utilities account for facilities operated at greater than 30 kV as transmission
and that distribution facilities are usually less than 40 kV.”[41] OTP’s 41.6 kV and 69 kV facilities are not of
“reduced voltage” within the meaning of FERC factor 7.[42] Applying the FERC factors as required by the
first Relevant Factor set out in Guideline 1 of the Boundary Order, supports a finding that OTP’s 41.6 kV and 69 kV
facilities should be classified as transmission.
36.
The second
“Relevant Factor” is whether the
facility is installed only for the purpose of serving a particular “customer”
(either generation or distribution). OTP’s
41.6 kV and 69 kV facilities do not serve a particular customer.[43] Application of this factor to OTP’s 41.6 kV
and 69 kV facilities supports a finding that the facilities perform a
transmission function.
37.
The third
“Relevant Factor” is: “Does the facility
serve wholesale load or other grouped load (e.g., retail load pockets), either
in looped or radial configuration?”
OTP’s 41.6 kV and 69 kV facilities serve wholesale load (i.e., municipal
customers, neighboring generation and transmission coops (G&T Coops), and
municipal power agencies (such as MPC, GRE, and MRES, etc.) as well as OTP
retail customers. OTP noted that there
are numerous transmission agreements between OTP and other utilities for the
wholesale provision of electricity. [44] Application of this factor to OTP’s 41.6 kV
and 69 kV facilities supports a finding that the facilities perform a
transmission function.
38.
The fourth
“Relevant Factor” is: “Was it designed
to serve single phase load?” The OTP
41.6 kV and 69 kV facilities were designed to transmit three-phase power. OTP has identified four locations where a
single phase load is connected to these facilities, but the total load
connected in this fashion is less than 0.3% of OTP’s total load.[45] Application of this factor to OTP’s 41.6 kV and
69 kV facilities supports a finding that the facilities perform a transmission
function.
39.
The fifth
“Relevant Factor” is: “Was it jointly
planned to meet load-serving needs of more than one utility? Are there contractual relationships
designating its use?” The vast majority
of OTP’s 41.6 kV and 69 kV facilities were jointly planned to meet the load
serving needs of more than one utility.
There are numerous contracts with neighboring utilities that govern the
use of these jointly planned facilities.
Most of these utilities are G&T Coops and municipal power agencies,
which provide only generation and transmission services to their members.[46] The vast majority of OTP’s transmission
system is covered by one or more of these agreements.[47] Application of this factor to OTP’s 41.6 kV
and 69 kV facilities supports a finding that the facilities perform a
transmission function.
40.
The sixth
“Relevant Factor” is: “What are the
anticipated future uses of the facility? Is it planned to be looped?” OTP removed all radial lines and all of OTP’s
remaining lines are looped.[48] Application of this factor to OTP’s 41.6 kV
and 69 kV facilities supports a finding that the facilities perform a
transmission function.
41.
The seventh “Relevant Factor” is: “Does the
facility interconnect two or more utilities?”
OTP has numerous interconnections and Integrated Transmission Agreements
(ITAs) . OTP has more than 200
interconnections with other utilities at just the 41.6 kV and 69 kV voltage
levels.[49] Application of this factor to OTP’s 41.6 kV
and 69 kV facilities supports a finding that these facilities perform a
transmission function.
42.
The eighth
“Relevant factor” is: “Who
operates the line? Who performs
maintenance and emergency repair? How is
it operated on a normal and contingent basis?”
OTP provides its own operation and maintenance for all of the 41.6 kV
and 69 kV facilities that it owns. For
joint transmission facilities (where different utilities own individual
segments of the line), each partner is responsible for the portion of each
facility it owns.[50] Application of this factor to OTP’s 41.6 kV
and 69 kV facilities supports a finding that the facilities perform a
transmission function.
43.
The ninth
“Relevant Factor” is: “What requirements
does the facility meet under NESC design and maintenance codes?” The NESC is the National Electric Safety
Code. Utilities must follow NESC codes as
they design electrical facilities. OTP’s
41.6 kV and 69 kV facilities meet NESC design and maintenance codes.[51] Application of this factor to OTP’s 41.6 kV
and 69 kV facilities supports a finding that the facilities perform a
transmission function.
44.
The tenth
“Relevant Factor” is: “What is the dominant functionality of the
facility?” Except for the few radial
facilities that OTP removed, the 41.6 kV and 69 kV facilities were identified
as used for the “transmission function 100 percent of the time.”[52] This requires a determination based on the
results of the other nine “Relevant Factors.” Based on the evaluation of the
facilities under the other nine Relevant Factors, the dominant functionality
and, in fact, the only functionality of these facilities, is transmission.[53]
45.
MCC asserted
that OTP needed to perform its analysis of the 41.6 kV and 69 kV facilities
using a segment-by-segment review, rather than the system level review that OTP
conducted. In response, OTP performed a
segment-by-segment analysis of the ten Relevant Factors. After conducting that additional study, OTP indicated
that 117 miles of radial lines (constituting two percent of the total facility
miles) would be removed from transmission treatment. In addition, OTP identified some minor
changes to the classification given to some substation equipment. The collective revenue requirement affect of
those changes was $7,200.[54]
47.
This guideline
is used to allocate substations (or portions of substations) to generation,
transmission or distribution.[55] In the course of Otter Tail’s review of its
substation records, it identified some combination substations. The specific property records for these
substations were reviewed. A list was
prepared of specific facilities that should be reclassified as a function other
than transmission.[56] Mr. Sherner identified two substations where
he believed that OTP may have improperly allocated a transformer.[57] Mr. Sherner’s criticism is irrelevant to the
core issue of whether the 41.6 kV and 69 kV facilities serve a transmission
function.
Summary of 41.6 kV and 69 kV Lines
|
|
Total Line Miles |
Line Miles Determined to Transmission |
Line Miles Determined to be Distribution |
|
41.6 kV |
3794 |
3682 |
112 |
|
69 kV |
207 |
202 |
5 |
Summary of
Substation Review
|
Transmission |
Adjustment to
Distribution |
Adjustment to
Generation |
Adjusted Transmission |
|
$54,429,051 |
$3,608,740 |
$1,505,020 |
$49,315,291 |
50.
Making the
foregoing changes to OTP’s facility designations results in a reduction of OTP’s
revenue requirement by approximately $7,200.[58]
2. MISO
and the Definition of Transmission.
51.
Mr. Erickson asserted
that when MISO took over operation of larger transmission facilities, only those
facilities rated at 100 kV and higher would qualify as transmission facilities.[59] OTP Transmission service using facilities
below 100 kV is governed by the MISO Tariff.[60] Nearly 50 percent of the branch transmission
facilities included in MISO’s Transmission Operator’s rates were below 100 kV.[61] While MISO
has affected how losses associated with facilities 100 kV and greater are
recovered, the recovery of line losses for 41.6 kV and 69 kV facilities has not
changed.[62] OTP maintained that MISO has limited its operations
to larger voltage facilities because it would otherwise have been overwhelmed
by the magnitude of the task of taking over the operation of all transmission.[63]
52.
OTP’s 41.6 kV
facilities have been included in MISO planning where they are impacted by new
generation projects.[64] MISO members’ transmission rates are
determined in MISO Tariff Attachment O.
That portion of the MISO tariff does not distinguish between voltage
levels.[65]
53.
MISO is
obligated by FERC Order 890 to include transmission facilities with voltage
below 100 kV in future planning. [66] Mr. Sherner confirmed the accuracy of this.[67] Mr. Sherner went on to state that MISO is
evaluating how to determine what qualifies as a transmission facility. Mr. Sherner’s recommendation was for MISO to
apply the Boundary Order and the
54.
Every member of
MISO, except Minnesota Power, includes lower voltage transmission in their FERC
Form 1 reports.[70] FERC Form 1 (RUS Form 12 for GRE) annual
reports provide the information for MISO Attachment O rates.[71] The following table is based on those
reports, which were attached to Ex. 116:
|
Utility |
Percentage of
Transmission above 115 kV |
Predominate voltage
below 115 kV and percentage of total transmission |
|
OTP |
23 % |
41.6 kV is 73% |
|
GRE |
33% |
69 kV is 56.6% |
|
IP&L |
35% |
69 kV is 31%, 34.5 kV is 34% (located in |
|
MDU |
41% |
41.6 kV is 35% |
|
NSP WI |
57% |
69 kV is 42% |
|
NSP MN |
60% |
69 kV is 38% |
58.
The use of
shield wires is not a criterion in either the Commission’s Boundary Order
or the FERC 7-Factor Test. The purpose of shield wires is to provide
protection from lightning strikes.
Shield wires do not affect capacity.[73] There was some suggestion that shield wires could
be a requirement for service quality purposes.[74] That would be a cost/benefit issue that is
not determinative of the function of the facility.
59.
OTP has
installed alternative methods protect against lightning strikes on those
facilities that do not rely on shield wires.
OTP noted out that 23 percent of its 115 kV lines do not have shield
wires.[75] There is no dispute that the 115 kV lines are
properly characterized as transmission.
60.
The presence or
absence of shield wires does not have any impact on the characterization of
lines as transmission or distribution.
B.
Demand-Based Transmission
Allocation.
62.
OTP noted that Xcel
Energy and IP&L both allocate all of their transmission in their
jurisdictional cost of service studies (“JCOSS”) based on demand.[76] This practice is supported as reasonable because
demand drives the cost of transmission. Each
of these utilities treats lower voltage facilities as transmission.[77] OTP noted that Xcel Energy has two
transmission rates, one for voltage below 69 kV and another for voltage at 69
kV or higher. While Xcel Energy has
different rates for these two transmission service levels, it uses the same
jurisdictional demand allocator for all transmission.[78]
63.
Transmission is
allocated based on demand because, as load (demand) increases, so does the need
to use higher voltage facilities.[79] The role of load in determining the voltage
levels was explained by Mr. Rogelstad as follows:
I think it
all comes down to load density. The
facilities that we’ve had in place, if you go back to 1986, were adequate to
meet the load requirements of the transmission system back then. And in some cases we’ve had to upgrade those
facilities, and I’ve provided a couple of examples in my testimony, where we
brought them from a 41.6 kV to 115 because of a load increase or generation
added that required a larger capability line.
And therefore, because of the relatively low load density and vastness
of our system, the 41.6 kV system is adequate.[80]
64.
Lower voltage
facilities cost less to install and operate.[81]
65.
67.
The Department
asserted that even if the 41.6 kV and 69 kV facilities are providing a
transmission function, there is no requirement that lower voltage transmission
be allocated based on demand. The
Department maintained that mileage is a more cost causative approach.[85] The Department did not offer an engineering
or operational basis for distinguishing between higher and lower voltage
facilities. The Department relied on Mr.
Schedin’s assertion that these lines offer no benefit outside of where they are
located.[86] Based on this, it was argued that high
voltage could be treated like a highway, while lower voltage could be treated
like a byway. No example was provided of
how such a distinction is currently being employed with respect to
transmission.[87] MISO Attachment O does not distinguish
between voltage levels in terms of rates.
68.
OTP maintained
that
69.
OTP noted that
70.
OTP maintained
that it has avoided incurring the significant costs of installing a new 115 kV
line by instead installing a new 230/41.6 kV substation. As a consequence, the existing 41.6 kV
facilities saved $14 million in investment to the benefit of the ratepayers.[90]
C.
The Proposed
Jurisdictional Allocation Changes Jeopardize OTP’s Ability to Recover Its Cost of
Service.
72.
OTP noted that each
of the Commissions in
73.
OTP has shown
that recovery of these cost shifts in
74.
In prior orders,
the Commission has expressly recognized the importance of using consistent
jurisdictional allocation processes between the jurisdictions in which a
multi-state utility does business.[93] The Commission’s decision rejecting a
jurisdictional allocation change in
75.
The Commission
has consistently adhered to its responsibility to set rates in the public
interest, which requires careful balancing of the interests of both the utility
and its ratepayers. The public interest is furthered when issues are resolved within the
bounds of accepted regulatory practice.[95] The public interest is not served if
reasonable consistency cannot be obtained among jurisdictions.
D.
Should
Transmission Be Functionalized Into High and Low Voltage.
77.
This identical
issue was addressed by FERC regarding OTP in 1980. As a result of being required by the U.S.
Supreme Court to provide transmission services to the municipality of Elbow
Lake, Minnesota,[96] the issue
arose whether Elbow Lake should only pay for the lower cost 41.6 kV facilities
used to serve it, or whether it should be required to pay a rolled-in rate that
included the cost of higher voltage facilities.
FERC ruled that OTP operated an integrated system, and consequently a
rolled-in rate should apply.[97]
78.
Mr. Sherner asserted
that if FERC were to address this issue fresh today it would apply the FERC
7-factors, as reflected in
79.
Mr. Sherner
testified that Enbridge should not contribute to the cost of lower voltage
facilities unless “OTP can successfully demonstrate they provide meaningful
ongoing or emergency support to their pumping stations.”[99] Mr. Rogelstad and OTP information responses
demonstrated that the lower voltage 41.6 kV and 69 kV facilities in the
81.
OTP noted that
it has transmission customers that connect to a substation connected directly
to 115 kV lines. OTP also has
transmission customers that connect to substations that are connected directly
to 41.6 kV and 69 kV transmission lines.
The lower voltage facilities are often “down stream” from higher voltage
facilities located “upstream.” Under the
approach advanced by Enbridge and MCC, transmission customers connected to
lower voltage facilities would be allocated costs for all transmission
facilities.[102] In contrast, transmission customers connected
to a 115 kV line would not be allocated any costs of the “downstream” 41.6 kV
and 69 kV facilities because they did not use the downstream facilities.[103]
82.
Enbridge is
located in the
83.
OTP maintained
that, following the approach of Enbridge and MCC, the retail customers located
in Bemidji (who are served by a substation connected to a 115 kV line) should
pay lower rates than retail customers located in Kalstad and Plummer (which are
served by a substation that is connected to a 41.6 kV line that is downstream
from the 115 kV line that serves Bemidji).[106] In other words Kalstad and Plummer customers
use both a 41.6 kV line and a 115 kV line while
84.
OTP also noted
that Enbridge, as a contributing cause to the need for higher cost 115 kV
transmission, could be allocated a greater portion of those costs. OTP noted that a synchronous condenser was
installed in the Solway peaking plant to provide needed voltage support to the
85.
Enbridge is the
only transmission customer of OTP which has its own step down transformer. Enbridge receives a lower rate due to this
factor and benefits from other load-based considerations. For OTP’s particular LGS rate, Enbridge is
the only customer served. OTP has no
customer that receives a lower (non-time of day) rate.[108] The terms under which Enbridge receives
service were negotiated. A change in
cost allocation would not, by itself, result in a lower rate for Enbridge.
86.
All of OTP’s
88.
The rate of
return (ROR) is determined by the weighted average cost of the various sources
of capital used by a company. Capital
structure generally refers to the mix of long- and short-term debt, preferred
stock, and common equity. Because the
various types of capital have different cost rates, each component is weighted
by its relative proportion in the overall mix of capital to determine the
overall cost of capital. As a result, the overall ROR is dependent on the costs
and types of capital used by the company.[109]
89.
For the
Commission to carry out its statutory responsibility to set rates that are just
and reasonable, a balancing of consumer and utility interests must be
performed. A reasonable rate enables an
investor-owned utility to recover its operating expenses, depreciation, and
taxes, as well as compete for funds in capital markets. Allowing a fair and reasonable return upon
the utility’s investment in property used to provide the utility service is a
factor in setting just and reasonable rates.
This return on investment in property is more commonly referred to as
return on equity (ROE).[110]
90.
OTP has no
existence separate from Otter Tail Corporation, thus OTP has no publicly traded
common stock. Since ROE is a
market-based concept, it is necessary to establish the ROE figure by other
means. The Commission has historically
relied upon the Discounted Cash Flow (DCF) analysis to derive ROE for rate
cases. This is the most widely accepted
model and one that has been used consistently as a starting point for
establishing the cost of equity in public utility cases before the Commission.[111]
91.
OTP conducted a comparison of its proposed capital structure
with comparable companies’ utility operating subsidiaries. This comparison was conducted with utility
holding company data because the utility operating subsidiaries are not
separately traded entities and, thus, lack direct market data. OTP maintained that its capital structure
should be evaluated by comparison to the capital structures of the utility
operating companies owned by the utility holding companies within the
comparable groups.[112]
92.
The Department
objected to OTP’s proposed capital structure as having too high a common equity
figure. The OAG proposed an even lower
equity figure, based on trends in the
|
|
OTP Proposal |
Department Proposal |
OAG Proposal |
|
Short Term Debt |
4.10% |
4.10% |
4.10% |
|
Long Term Debt |
39.40% |
42.30% |
44.75% |
|
Preferred Stock |
3.60% |
3.60% |
3.60% |
|
Common Equity |
52.9% |
50.00% |
47.55% |
|
Total |
100.0% |
100.0% |
100.0% |
93.
The effect of
the Department and OAG proposals is to move more of the accounting structure
into lower cost categories, thereby reducing the overall revenue required to
meet the ROE figure. OAG further
recommended that OTP be made a separate subsidiary of a newly formed holding
company under Otter Tail Corporation.[114]
94.
OTP maintained
that its proposed capital structure is supported by OTP’s comparatively low
cost of long term debt (LTD), which is 6.32%.
This figure was contrasted with the LTD cost of 6.59% experienced by Otter
Tail Corporation.[115] OTP maintained that its cost of LTD has been
consistently lower than that of other
|
|
2003 |
2004 |
2005 |
2006 |
|
|
6.83% |
6.60% |
6.03% |
5.87% |
|
OTP |
6.31% |
6.30% |
6.36% |
6.33% |
|
Interstate |
7.09% |
6.88% |
6.81% |
6.61% |
|
Xcel-MN |
7.88% |
7.40% |
6.95% |
6.79% |
|
Xcel-ND |
7.87% |
7.32% |
6.97% |
6.83% |
|
MDU-ND |
8.78% |
8.62% |
8.71% |
7.98% |
|
Source: Annual state regulatory
reports |
|
|
||
96.
Based on its
proposed capital structure, OTP recommended an overall rate of return (“ROR”)
of 8.89%, including a ROE of 11.25%, as follows:[117]
|
|
Percent of Total |
Cost |
Weighted Cost |
|
Short Term Debt |
4.1% |
6.52% |
0.27% |
|
Long Term Debt |
39.4% |
6.32% |
2.49% |
|
Preferred Stock |
3.6% |
4.75% |
0.17% |
|
Common Equity |
52.9% |
11.25% |
5.96% |
|
Total |
100.0% |
|
8.89% |
There was no dispute regarding: (1) the costs of LTD,
Short Term Debt (“STD”), or Preferred Stock; or (2) portions of the capital
structure for STD or Preferred Stock.
|
|
ROE |
Common Equity Ratio |
ROR |
|
Company |
11.25% |
52.9% |
8.89% |
|
Department |
10.91% |
50.0% |
8.57% |
|
OAG |
9.69% |
47.55% |
7.97% |
C.
Standards for
Determination of the ROE.
98.
The basic
standards for the determination of ROE are set forth in Hope[118] and
D.
The Discounted
Cash Flow (“DCF”) Model.
100. The Discounted Cash Flow (“DCF”) model is based on
the theory that a stock’s price represents the present value of all future
expected cash flows. The DCF model is
widely used to determine ROEs for utilities.[120] The DCF model expresses the ROE as the sum of
the expected dividend yield and long-term growth rate.[121]
101. The most common form of the DCF model is the
“Constant Growth” form. Under the
Constant Growth DCF model, the price of a stock is a function of the collective
ROE required by investors, which is determined as the sum of dividend yield and
growth.[122]
102. Multi-period DCF models have also been proposed for
use in utility proceedings to calculate the cost of equity. The difference between the Constant Growth and
Multi-period DCF models are in the assumptions for rates of growth to be
experienced throughout the period studied.
Multi-period DCF models are reasonable means of calculating the cost of
equity, but they can be more sensitive to the inputs and assumptions used by
the analyst.[123] The Commission has consistently relied on the
Constant Growth DCF model and has rejected the suggestion to rely solely on multi-period
DCF models.[124]
103. Dr. Amit analyzed OTP’s reasonable costs of equity
using both a Constant Growth DCF and a multi-period DCF analysis to support the
Department’s position on ROE. The Two
Growth DCF essentially requires the same variables as the Constant Growth DCF,
except there are two growth rates, one for the first period, and a second rate
for long-term growth rate. Dr. Amit used
a “Two Growth DCF” in a multi-stage DCF model for three of the companies in his
comparable group.[125]
1.
Summary of the
Company’s ROE Recommendation.
106. OTP proposed an ROE of 11.25% based on Mr. Hevert’s
analysis. Mr. Hevert relied primarily
on a Constant Growth DCF, which initially resulted in mean ROE figures of 10.78
and 10.82%.[126] Mr. Hevert also incorporated the results of his
Capital Asset Pricing Model (“CAPM”) analysis to arrive at the ROE figure. OTP contended that his analysis was corroborated
by comparison to 43 recent ROE awards to vertically integrated utilities in
other jurisdictions.[127] The results of Mr. Hevert’s analyses, applied
to the various proxy groups, are as follows:[128]
|
|
Mean Low |
Mean |
Mean High |
|
Hevert Revised Proxy Group |
10.28% |
11.51% |
12.74% |
|
Combined Proxy Group |
10.15% |
11.26% |
12.37% |
|
Amit Proxy Group |
10.98% |
12.38% |
13.78% |
|
Kaml Proxy Group |
9.70% |
10.65% |
11.61% |
|
AVERAGE |
10.28% |
11.45% |
12.63% |
|
|
Amit Group[129] |
Hevert Updated Group[130] |
Kaml Group[131] |
|
DPL, Inc. |
|
|
Ö |
|
|
Ö |
Ö |
|
|
Empire District Electric |
Ö |
Ö |
Ö |
|
Entergy Corp. |
Ö |
Ö |
|
|
Pinnacle West Capital |
Ö |
Ö |
Ö |
|
Progress Energy |
Ö |
Ö |
Ö |
|
Westar Energy |
|
Ö |
Ö |
|
Dominion Resources |
Ö |
|
|
|
American Electric Power |
|
|
Ö |
|
Cleco Corporation |
|
|
Ö |
|
PNM Resources |
|
|
Ö |
|
Southern Company |
|
|
Ö |
|
Xcel Energy |
|
|
Ö |
108. DPL. Utilities that are subject to retail
competition (such as DPL) have significantly different risks than vertically
integrated utilities in
109.
110. Entergy. Entergy was included by both Dr. Amit and Mr.
Hevert, but excluded by Mr. Kaml because of a proposed restructuring.[137] OTP contended that Entergy should be included
because: (i) it met all appropriate screening criteria; (ii) there was no
indication of any significant effect on the price of Entergy stock; and (iii) a
portion of the proposed restructuring was rejected more than one year ago.[138] Entergy is appropriate for inclusion in the
Comparison Group.
111. Cleco and
Southern. Mr. Kaml
included both Cleco and Southern in his group.
OTP and the Department maintained that the beta coefficients of these
companies rendered them not comparable to OTP.
Beta coefficients are appropriate screens that are used by investors.[139] Cleco and Southern should be excluded from
the comparable group.
112. PNM. PNM announced agreements that involve the
transfer of almost 25% of its assets in January 2008.[140] While this transfer was announced after the
analyses were performed, excluding PNM for this reason is appropriate to
maintain the most accurate analysis possible.[141]
113. Xcel
Energy. Dr. Amit
excluded Xcel Energy because it is not categorized as an electric company.[142] Mr. Hevert excluded Xcel Energy because a
large portion of its revenues and earnings result from its regulated natural
gas business.[143] A utility with substantial natural gas
business is not comparable to OTP, which has no natural gas business. Xcel Energy should be excluded from the
comparable group
114. American
Electric. Mr. Hevert
excluded American Electric because it did not meet his beta screen.[144] Dr. Amit excluded it because it is subject to
retail competition.[145] Screens for beta and retail competition are
appropriate. American Electric should be
excluded.
115. Westar. Dr. Amit excluded Westar because of its SIC
industry code.[146] Mr. Hevert included Westar because it met all
of his screening criteria.[147] Excluding Westar results in increases of Mr.
Hevert’s updated mean and high DCF results by 45 and 70 basis points
respectively.[148]
116. Dominion. Dr. Amit included Dominion. Mr. Hevert excluded Dominion because of
substantial revenues and earnings from non-regulated operations.[149] If Dominion was included, Mr. Hevert’s
updated mean and high DCF results would have increased by 42 and 39 basis
points respectively.[150]
117. Both of Dr. Amit’s and Mr. Hevert’s comparable groups
are appropriate. Of the two, Dr. Amit’s
provides the closest comparison to OTP.
Adjusting Mr. Kaml’s comparable group (by removing AEP, Cleco, DPL, PNM,
Southern, and Xcel Energy) would increase his mean DCF by 25 basis points.[151]
3. Earnings
Per Share Growth Forecasts.
118. The DCF model is based on long-term growth and assumes cash flows in perpetuity and a
constant dividend payout ratio. In the
long-run, book value per share (“BVPS”) growth and dividend per share (“DPS”) growth
are derived from earnings per share (“EPS”) growth.[152]
119. Dr. Amit and Mr. Hevert relied solely on EPS growth
estimates. They maintained that this is
appropriate because: (i) EPS growth is the only logical source of long term
growth, as investors know;[153] and (ii)
objective data demonstrates that EPS is the only growth estimate in which
investors place sufficient reliance to affect the price of electric utilities’
stock in general or the comparable companies considered by Dr. Amit, Mr.
Hevert, and Mr. Kaml.[154]
120. Mr. Kaml gave equal consideration to BVPS and DPS growth
rates. Mr. Kaml’s use of BVPS and DPS
growth rates reduced the results of a DCF analysis of his comparable group by
53 basis points. Mr. Hevert maintained
that updating Mr. Kaml’s data and focusing on EPS growth rates would increase
his mean DCF result to 10.47%, before adjustment of his comparison group and
inclusion of flotation cost recovery.[155]
121. Over the long-run, both BVPS and DPS are derived from
EPS growth. While in the short run,
expected growth rates of DPS, BVPS, and EPS may differ, the long-run expected
BVPS and DPS growth rate must equal the EPS expected growth rates. As a result, expected EPS growth is the
foundation of growth in the DCF model.[156] Since the DCF model assumes cash flows in
perpetuity and a constant dividend payout ratio, EPS, rather than DPS or BVPS,
is the appropriate measure of growth for the DCF model.[157]
122. Mr. Hevert contended that that EPS growth projections
are the only measure of growth that have a statistically significant and
meaningful effect on investors’ stock purchase decisions (and resulting prices)
for: (i) electric utility stocks in general; and (ii) the comparison companies
used by Mr. Kaml, Dr. Amit, or Mr. Hevert.
Mr. Hevert maintained that neither DPS nor BVPS growth rates had any
statistically significant effect as a predictor of investors’ stock valuations.[158]
123. Emphasizing EPS growth projections appropriate blends
the need to use price data based on information that is as recent as possible,
yet avoids the impact of significant short-term market fluctuations. The most recent 30-day period as used by Dr.
Amit accomplished this purpose. The projected
EPS growth rates are the appropriate growth rates to be used in a DCF analysis
or a TGDCF analysis because long-term sustainable DPS growth rates are solely
determined by the EPS growth rates.[159]
124. The Department relied upon the TGDCF to appropriately
account for the fact that some of the projected EPS growth rates may not be
sustainable in the long-run. (This same
problem exists with the projected book value per share (“BPS”) and dividend per
share (“DPS”) growth rates.) The
Department’s recommended ROE for OTP is the most appropriate and most
reasonable ROE in this proceeding because it is the only ROE that used the most
recent available dividend yields and projected growth rates, used the EPS
projected growth rates which are the most appropriate to use in a DCF or TGDCF
analysis, and accounted for the some of the projected EPS growth rates being
unsustainable in the long-run.[160]
125. Dr. Amit used a 30-day averaging period to eliminate
the effect of potentially aberrational prices in the dividend yield
calculation.[161] Mr. Hevert accepted a 30-day averaging period
in his updated DCF analysis[162] and
determined a dividend yield of 4.31%.[163] OTP, the Department, and the OAG all included
a 1/2 year growth component,[164] to address
the different times during the year when the companies in the comparison groups
issued dividends.[165]
126. The dividend yields that were included in the data
from which the OAG determined its ROE recommendation averaged about 4.41% for
the three month period ending December 31, 2007[166] and
subsequently increased to 4.54%.[167]
127. The Department noted that updating information in the
DCF model is important since the model is a forward-looking assessment of the
cost of equity. Because current stock
prices incorporate all publicly available information, older data should be
avoided.[168] The same assertion was made regarding growth
forecasts, which should also match the period of the stock price information.[169]
128. Since more current information is now available than
when the parties filed their direct testimony, the more current information
should be used.[170] Dr. Amit noted the need for updated
information in times of market changes and demonstrated that by reference to
the irrelevance of data from late 2007 in the context of current capital market
conditions.[171] Mr. Kaml acknowledged that it was important to
use the most current information that is available.[172] He also acknowledged that the Commission
typically uses updated information when it is
available.[173] Mr. Kaml did not provide updated information,
and had not reviewed more current information for his comparable group after
the cut off of his data as of December 31, 2007.[174] Dr. Amit noted, however, that the impact of
using his updated data was a “slight increase,” amounting to 20 basis points
difference in the ROE and only 10 basis points in the ROR.[175]
129. Market conditions have increased the cost of equity
since the time of the parties’ direct testimony, as reflected in the
surrebuttal analyses of Dr. Amit, whose recommended ROE increased by 20 basis
points[176] and in the
rebuttal analyses of Mr. Hevert, whose mean DCF analyses increased by 51
basis points using the six companies in his revised comparable group.[177] Updated information alone would have
increased Mr. Kaml’s mean DCF by 25 basis points.[178] Including updated information is important
for precision in rate setting, but the updating of information will not support
adopting one model over another, since the differences are going to be insignificant
compared to the differences in modeling.
130. Mr. Hevert and Dr. Amit proposed recovery of
flotation costs by the same “Amortization Method” that the Commission has used
in prior cases. The evidence provided by
the Company meets all of the criteria for flotation cost recovery in the 2004 Great Plains Rate Case,[179] the 1994
131. The recovery of flotation costs related to the
issuance of common stock is closely analogous to the recovery of issuance costs
for LTD. To deny recovery of common
stock flotation costs because there was no common stock issuance planned for
the test year would be comparable to allowing the recovery of LTD issuance
costs only in years when the LTD debt was issued. There is no requirement that limits the
recovery of those costs to LTD issued in the test year or to investments made
in the test year, and there is similarly no logical basis to limit recovery of
common stock flotation costs to common stock issued in the test year.[182]
133. It is inconsistent to think of flotation costs as a
cost that is appropriately recovered only if stock is issued in the test year. While a test year limitation is an
appropriate requirement for when expenses
have been incurred, it is not an
appropriate requirement for when long-term
costs, such as rate base or permanent capital have been incurred. Flotation costs associated with common stock
issuances should be treated the same as issuance costs of LTD, which are
amortized over the life of the LTD.[183]
134. The Amortization Method matches the recovery of the
cost to the useful life of the capital, which is permanent with common
stock. In contrast, the Current Recovery
Method allocates all flotation costs to only current ratepayers, who receive
only a portion of the benefits from new common stock issuances. The Current Recovery Method is counter to the
basic principles of capital cost recovery under regulated rates.[184]
135. Under capital cost recovery principles, the cost
recovery of an investment must be spread over the life of the investment to
best match cost recovery with the benefits provided. Since the issued common stock remains on the
utility’s balance sheet and continues to provide benefits to ratepayers
indefinitely, it is appropriate to recover flotation costs via the Amortization
Method which matches the period of the benefit.
Otherwise, current ratepayers would pay all the costs of an investment
that continue to provide benefits for future ratepayers.[185] Mr. Kaml agreed that common stock proceeds
are used to finance long-term investments and that the Current Recovery Method
recovers all common stock issuance costs from current ratepayers.[186]
136. The purpose of a flotation cost adjustment is to
prevent dilution and allow investors to earn their required rate of return even
during years in which no new common equity shares are issued.[187] Dr. Amit demonstrated how dilution occurs
with a mathematical model.[188]
137. Mr. Kaml asserted that the need for recovery of
flotation costs should be limited to common stock issuances at less than book
value.[189] However, the purpose of flotation cost
recovery is to prevent dilution, and that dilution is based on the relationship
of issuance proceeds received by the issuing utility to the market value of the stock, not the book
value.
138. The authorized ROE should reflect the level at which
the regulated utility is able to attract capital (i.e., the market price).
Accordingly, recovery of those issuance costs is needed so that the
authorized ROE is not diminished by those costs.[190] Without recovery of flotation costs, the
authorized ROE may not be earned because costs associated with the utility’s
common stock have not been recovered.[191]
139. OTP has provided evidence of investment plans that include
$759 million of investments in total.
Approximately $336 million of that investment relates to the proposed Big
Stone II project.[192] The remaining $423 million relates to other
projects, including $106 million for additional wind generation and related
transmission.[193] OTP noted that its capital expenditure
program is well above average and considerably more extensive than those
undertaken by the proxy group companies.
As a general matter, OTP maintains that the financial community
recognizes that additional risks are associated with substantial capital
expenditures.[194] OTP indicated that it will need sources of
capital beyond its earnings to carry out its investment plans.[195] The OAG did not provide any evidence that
would call into question OTP’s investment plan or OTP’s need to issue common
stock to capitalize that investment plan.[196]
140. In raising new capital, continuing a high ratio of
equity to total capitalization is needed for OTP to maintain its strong credit
ratings.[197] New common stock will be needed to maintain a
balance of debt and common equity since capitalizing the anticipated investment
projects primarily through the issuance of debt instruments would substantially
reduce the ratio of common equity to total capitalization.
d.
Prior Commission Decisions.
142. In the 1994
Issuance
or flotation costs are not simply for use in years when the company is issuing
common stock. They represent the
difference between what the investors paid and the company received during
public offerings, and, because there is no fixed life, as there is with a bond,
they must be recovered through a return adjustment.[198]
In the 2005
Xcel Energy Rate Case, the Commission recognized that such a requirement
could impede the utility’s ability to raise capital needed to fund investment,
saying in part:
In
this case, the absence of affirmative, record evidence that Xcel plans to issue
stock during the test year clearly cuts in favor of denying the entire
25-basis-point adjustment. At the same
time, there is no affirmative, record evidence that the Company will not issue
stock during that time, the parties did not address the issue, and the record
contains many references to plans for an aggressive capital improvement
program.
***
The
commission has no intention of hindering Company efforts to raise capital for
this program, parts of which are critical to maintaining system reliability and
to implementing state policies promoting the development of renewable
generation technologies … .[199]
143. The 2003
Interstate Rate Case,[200] which was
discussed in the 2005 Xcel Energy Rate
Case,[201] does not
support the conclusion that flotation costs depend on test year stock
issuances. In that case: (i) the utility
did not request flotation cost recovery;[202] and (ii)
the utility presented no evidence of either actual or projected issuance
costs.[203] That case also reflected the unusual
circumstance of the Commission rejecting a settlement because the ROE was too
high.[204]
144. The 2004
e.
Use of the Amortization Method.
145. The Commission uses the Amortization Method, which
adjusts the dividend yield. This
approach is comparable to the recovery of the issuance costs of LTD.[207] The Commission described and approved the
Amortization Method in 2004 Great Plains
Rate Case,[208] as follows:
The
adjustment was made by dividing the expected dividend yield by (1 – percentage
flotation costs).[209]
146. Mr. Kaml acknowledged that the Commission has used
the Amortization Method when allows recovery of flotation costs.[210] Mr. Kaml also acknowledged the importance of
precedent, stating: “Once one method is adopted, it must be continued.”[211] The Amortization Method used by Dr. Amit and
Mr. Hevert complies with the Commission’s prior decisions on this issue.[212]
147. Mr. Kaml acknowledged that his proposed test year
limitation was quite restrictive,[213] and that
his recommendation is more severe and restrictive than what is required under
the FERC standards.[214]
148. OTP’s financial situation meets the FERC requirements
for flotation cost recovery, even under the “Current Recovery Method.” Under Boston
Edison, flotation cost recovery was allowed based on a showing “that [the
utility] will require external financing to complete its construction program”[215] and that it
had a plan to issue common stock “during the next five years.”[216]
149. The Company has demonstrated its need for common
stock issuance in the next 5 years under its capital investment plan, which
calls for an investment of approximately $739 million.[217] An award of flotation costs is appropriate
under these circumstances.
150. With a $100 million common stock issuance and
flotation costs of 4.41%[218] (as Dr.
Amit found), the issuance costs would be $4,410,000 ($100,000,000 x
4.41%). The Company’s $759 million
investment plan over the next 5 years is very likely to require substantial
common stock issuances.[219] Under the Current Recovery Method, all of
those $4,410,000 costs would be recovered from current ratepayers, even though
investments made with the $100 million would serve ratepayers for many
years. Under the Amortization Method, a
20 basis point flotation cost adjustment determined by Dr. Amit[220] would add
approximately $341,000 to the revenue requirement[221] and the 18
basis point flotation cost adjustment determined by Mr. Hevert[222] would add
approximately $307,000 to the revenue requirement.[223] The Amortization Method provides a far better
match of costs and benefits for ratepayers.
151. OTP maintained that ROE recommendations of the
Department and the Company are corroborated by mainstream of other decisions
relating to vertically integrated utilities, such as OTP.[224] OTP contrasted Mr. Kaml’s ROE recommendation
as being lower than any authorized
rate award of 42 awards in jurisdictions that have not adopted electric
restructuring at the retail level from 2006 through 2008. Presented graphically, OTP described the
comparison as follows:[225]
The results of many cases (42 cases since 2006)
eliminate any realistic possibility that unusual facts could explain all of these
results. As a result, the ROE awards in
other states provide a useful benchmark to corroborate the results of the
record in this proceeding.[227]
Third, as the ALJ herself suggested, the Commission
has taken administrative notice of a list of updated ROE decisions from other
jurisdictions provided by the Company. The ALJ suggested that updated information
on those decisions might support adjusting her 9.5 percent ROE recommendation
upward. While the probative value of ROEs set in other jurisdictions is limited
because the record does not allow the Commission to assess the differing
regulatory circumstances affecting those awards, they do provide some window to
national context and, as such, can serve a limited function as a check on
reasonableness.[228]
154. OTP also noted that PNM debt securities were downgraded
to non-investment grade levels (a/k/a “junk”) by Fitch within days of a recommended
decision by a
155. The competing recommendations for an award of ROE are
as follows:[231]
|
|
Low |
Mean |
High |
|
Hevert Constant Growth DCF |
10.28% |
11.51% |
12.74% |
|
Amit Two Growth DCF |
9.90% |
10.91% |
11.85% |
|
Kaml Constant Growth DCF |
Not calculated |
9.69% |
Not calculated |
157. Mr. Kaml’s analysis and ROE recommendation are very
unlike the recommendations of either Dr. Amit or Mr. Hevert, and is an extreme
outlier from the mainstream of ROE awards in other states. Updating Mr. Kaml’s data, eliminating DPS and
BVPS growth rates, removing dissimilar utilities, and applying the Amortization
Method for flotation costs would lead to a 10.91% ROE, which is consistent with
the rate calculated on behalf of the Department.[232]
|
|
Percent of Total |
Cost |
Weighted Cost |
|
Short Term Debt |
4.1% |
6.52% |
0.27% |
|
Long Term Debt |
42.3% |
6.32% |
2.67% |
|
Preferred Stock |
3.6% |
4.75% |
0.17% |
|
Common Equity |
50.00% |
10.91% |
5.46% |
|
Total (ROR) |
100.0% |
|
8.57% |
1.
How Asset-Based
Margins Should Be Credited.
162. In its initial filing, OTP proposed paying 100% of
the asset-based margins through the fuel clause adjustment (“FCA”). OTP proposed paying 100% of asset-based
margins through the FCA because the Commission approved an FCA sharing
mechanism for asset-based margins in the 2005
Xcel Energy Rate Case[233] and the IPL
rate case (Docket No. E017/GR-05-748).[234] MCC also supported crediting asset-based
margins to the fuel cost revenue requirement.[235]
163. In their Direct Testimonies, the Department and the
OAG proposed that asset-based margins be credited instead to the base rate
revenue requirement.[236] The Department stated that this was
appropriate because OTP’s asset-based margins are consistent in amount from
year to year, making it possible to determine a reasonable amount of credit.[237] The OAG proposed a credit to the base rate
revenue requirement to provide the Company an incentive to obtain margins equal
to the amount of credit, and to reduce the magnitude of the increase in base
rates.[238]
164. OTP agreed to credit asset-based margins to the base
rate revenue requirement, as long as the fixed credit amount is reasonable.[239] MCC did not address this issue in its
Rebuttal Testimony and apparently does not oppose crediting the asset-based
margins to the base rate revenue requirement.[240]
2.
Selecting a
Reasonable Fixed Credit.
Year Amount
2002 $2.376
million
2003 $4.339
million
2004 $4.292
million
2005 $5.953
million
2006 $5.745
million
2007 $5.658
million[241]
169. The Department and OTP are in agreement except for
the treatment of 2005 in the historical average. The Department excluded the 2002 margins
because they were comparatively lower.
OTP excluded 2002 because it was the first year of MISO operations,
which resulted in the amount of asset-based margins received in 2002 being
significantly below those of subsequent years.[242]
170. OTP excluded 2005 asset-based margins because 2005
was the first year of MISO Day 2, and OTP maintained that it did an excellent
job of anticipating the market opportunities that were presented in that
year. With each subsequent year, OTP’s
margins have been smaller, reflecting the changes in MISO Day 2 operations and
the increasing sophistication of the other market participants.[243]
3. The OAG Proposal to Pass Additional Asset-Based Margins through
the FCA.
173. The OAG proposed that any asset-based margins in
excess of the credited amount be paid to ratepayers through the FCA. Under the OAG proposal, if actual margins are
less, the Company would absorb the loss.
Conversely, if there are additional margins in excess of the amount of
the credit, those would be paid to the ratepayers. In comparison, under the Company’s and
Department’s proposals, any additional margins would be applied to meet OTP’s
future revenue requirement, offsetting some of the effects of inflation and other
cost increases and delaying the need for a rate case. This treatment was used by OTP from 2003 through
2007 to delay the need for a rate case.[244]
174. The OAG maintained that asset-based margin
“transactions create costs for ratepayers, including higher costs for plant in
service, higher inventories of fuel, materials and supplies, depreciation and
other costs.”[245] OTP responded that if costs did increase as a
result of asset-based margin transactions between rate cases, the Company could
not recover those cost increases except by filing another rate case. [246] OTP contended that ratepayers were not harmed
by the additional sales. To the extent that
those costs increased between rate cases, OTP maintained that it should be
allowed to use the associated margins to cover those cost increases.
177. The Commission’s policy against single-issue
ratemaking was affirmed by the Minnesota Court of Appeals in Matter of
The PUC
could not have simply removed the transferred property from
181. As with asset-based margins, there are two primary
methods for compensating ratepayers for this activity, a credit to base rates or
payments made through the FCA. Unlike
asset-based margins, all of the parties propose that payments for non-asset
based margins be made through the FCA.
The difference is largely because the amount of non-asset based margins
is volatile and risky. Non-asset based
margins can even reflect net losses. For
that reason, only net positive margins are to be shared with ratepayers on an
annual basis.[249]
184. OTP proposed paying 10 percent of its non-asset based
margins (non-regulated profits) to the ratepayers, by passing those margins
through the fuel clause. In Docket No.
E002/GR-85-1428, Xcel Energy’s proposal to share 25 percent of the margins,
coupled with Xcel Energy bearing the full risk that non-asset based margins
might be negative, was presented to the Commission in a settlement that the
Commission approved.[250]
per customer 2.9 times larger
per kWh 2.25 times larger
per retail revenue dollars 2.5 times larger[251]
186. The OAG proposed that the 25 percent sharing used by
Xcel Energy be required of OTP.[252] The OAG offered two explanations for its
position. First, OTP’s analysis in its
Direct Testimony did not consider the difference in the mix of customers.[253] The table in the foregoing finding shows that
the concern is unfounded. On a per kWh
basis (which eliminates customer differences entirely), OTP’s proposal is 2.25
times more generous than the Xcel Energy proposal. Second, the OAG maintained that OTP only
provided comparison information for 2006.
OTP responded that small variations from year-to-year in each utility’s
performance in non-asset based activities were possible, but that such variations
would not change the ultimate conclusion that OTP’s proposal is significantly
more generous.[254]
188. Crediting $993,173 to the base rate revenue
requirement would be a fixed credit based on volumes of non-asset sales during
2006. OTP maintained that this figure is
a snap shot amount that ignores the volatility and risk (since annual margins
could be negative) associated with non-asset based margins. OTP asserted that requiring a fixed credit to
base rates is inconsistent with the Department’s justification for providing a
percentage credit to the fuel cost revenue requirement.[255]
189. The Department maintained that the $993,173 credit is
based on a determination of non-regulated costs, pursuant to the standards set
out in Docket 1008.[256] OTP indicated that this was the amount of
regulated costs that OTP moved below the line in 2006 to provide a credit to
the base revenue requirement. OTP
indicated that the amount was not based on a cost analysis. [257]
190. OTP asserted that even if volumes were the
appropriate allocator for determining credits, applying Docket 1008 principles
does not support first allocating costs and then also taking 10 percent of the
profit of the non-regulated business activity.[258]
191. OTP characterized the Department’s proposal as the equivalent
to crediting 48 percent of these margins.[259] As stated by Mr. Brause:
The
Department’s approach would create a subsidy to the ratepayers and would be
confiscatory. Consequently, it would
reduce, if not remove entirely, OTP’s reasons for engaging in this highly risky
enterprise. If OTP ceases this activity,
its costs are not expected to decrease materially and certainly would not
decrease by an amount equal to 10 percent of the anticipated margins. As recognized in the approved Xcel Energy
settlement, utilities are not required to engage in this unregulated business.[260]
192. The MCC proposed that 30% of the non-asset based
margins be paid to the ratepayers, based on an attempt to create a fully
allocated cost requirement for this activity.[261] OTP maintained that the extent of commingling
sales activities for both asset-based and non-asset sales made determination of
a stand-alone cost for either activity virtually impossible.
193. OTP identified several problems with the MCC
methodology. All incentive payments were
removed in direct conflict with the MCC’s other testimony that it is
appropriate to pay incentives to marketers.
Loading factors were inappropriately applied to incentives, when labor
costs already recovered those loadings (double counting costs). An “office space” charge was applied without
any support for that charge. The entire
“office space” charge was added to the
C.
Ancillary
Service Market Margins.
196. ASM margins include margins from spinning reserves,
regulation reserves and supplemental reserve requirements. OTP and the Department propose that 80% of
any such ASM margins be paid to ratepayers through the FCA. The parties indicated that this is the same
treatment of ASM margins approved by the Commission for Xcel Energy. OTP has not previously had any ASM margins
and agreed to implement such sharing within 60 days after OTP begins receiving
such revenues. The only limitation would
be a delay to the start date if OTP determines that beginning within 60 days is
not technically feasible.[263] OTP committed to addressing any lag resulting
from such a delay upon implementation.[264]
197. OTP agreed to revisit this treatment of ASM margins
once MISO Day 3 begins.[265]
199. While OTP may be required to engage in these
activities in the future under MISO Day 3, the details and nature of those
activities are not currently known, and if a change is appropriate based on
better knowledge, OTP has agreed that a prospective change would be
appropriate.[266]
D.
Future Carbon
Credits and Renewable Energy Credits.
200. The MCC proposed that OTP be required to share future
carbon credits and Renewable Energy Credits (RECs).[267] OTP maintained that, until more is known
about how these markets will be structured and how utilities will participate
in them, requiring a sharing mechanism is premature. OTP asserted that these are issues that
should be addressed for all
201. The MCC provided no specifics on its proposal. The Commission only recently began addressing
the trading of carbon credits and RECs.
The Commission has declined to address the issue of cost recovery.[269] MCC’s proposal should not be adopted as part
of this proceeding.
MISO divides its operations into categories, including “Day 1”
operations (dealing with security, outages, tariffs, transmission-line
congestion and energy imbalances, billings and settlements, and market
monitoring) and “Day 2” operations (implementing a competitive wholesale market
for electricity, including locational marginal pricing and financial
transmission rights).[270]
205. MISO’s cost of administering its Day 1 activities are
recovered through its Schedule 10 charges.
Mr. Beithon provided a detailed description of the MISO Day 1 activities
along with a discussion of the resulting costs and benefits.[271] The Commission has approved full cost
recovery of Schedule 10 charges in the two most recent electric rate cases
(IP&L, Docket No. E001/GR-05-748 and 2005
Xcel Energy Rate Case). No party
objected to OTP recovering its Schedule 10 costs.
206. The Commission has determined that utilities,
including OTP, can recover MISO Day 2 costs through the FCA, with the exception
of MISO Schedule 16 and 17 charges.[272] Schedule 16 and 17 charges were determined to
be administrative and not energy in nature.
For that reason, Schedule 16 and 17 costs are recovered through base
rates rather than through the FCA. The
Commission described this cost recovery mechanism as follows:
Each
petitioning utility may use deferred accounting for MISO Schedule 16 and 17
costs incurred since April 1, 2005 [the start of Day 2]. Each utility may continue deferring Schedule
16 and 17 costs without interest until the earlier of the utility’s next
electric rate case or March 1, 2009.[273]
207. OTP is seeking to recover both its 2006 test year
Schedule 16 and 17 costs of $329,239 and its deferred Schedule 16 and 17 costs
of $292,895. OTP provided a detailed description
of MISO Day 2 activities, including a cost/benefit analysis.[274] The Department requested that OTP provide
additional information concerning costs, avoided costs, revenues and lost
revenues.[275] In response, OTP provided additional
information on both the actual costs incurred and the revenues received. OTP was not able to provide information on
what the Company’s energy costs would have been in the absence of MISO. OTP explained the absence of information as
follows:
Wholesale
energy prices are dependent on a large number of factors for the MISO
regions. Some of those include:
Overall balance of
supply and demand;
Prices for generating
station fuels (coal, natural gas, and oil);
Generating station
availability;
Transmission line
availability;
Weather patterns;
Non-conforming load
requirements; and
Availability of hydro
resources.
Determining
the Company’s avoided energy costs and lost revenues would involve replicating
accurately all of the factors identified above in the context of a pre-Day
2/pre-MISO environment. It is simply not
possible to know these factors, because it is not possible to eliminate the
impact that MISO had on the market.[276]
208. OTP’s cost/benefit analysis of those costs that could
be quantified demonstrated that OTP had:
$1.9
million in avoided transmission charges for capacity purchases;
$1.5
million reduction in the need for spinning reserves;
$6.7
million avoided due to a much needed method of addressing OTP’s obligations to
supply regulation and load following services to generators in its control
area; and
$2.0
million in additional transmission revenues.
209. OTP has demonstrated benefits exceeding $12 million;
compared to the 2006 test year costs of $329,239 and the deferred Schedule 16
and 17 costs of $292,895.[277] In response, the Department modified its
position and agreed that the benefits of MISO Day 2 outweigh the costs and
consequently the 2006 test year costs of $329,239 should be approved.[278]
210. While the Department concludes that the benefits of
Day 2 exceed the costs for the purpose of allowing cost recovery of 2006 test
year Schedule 16 and 17 costs, it asserts that none of the deferred Schedule 16
and 17 costs should be recovered. Ms.
Campbell argues that wholesale margins were not shared with ratepayers during
the deferral period of April 2005 to November 1, 2007 (the date interim rates
took effect), and that energy costs increased during the deferral period while
the “wholesale sector reaped significant profits gained through MISO Day 2.”[279] OTP asserted that the Company shared
wholesale margins during the 2005-2007 deferral period in the same manner that
justified allowing recovery of the 2006 test year amount; and that OTP properly
allocated Schedule 16 and 17 costs to the wholesale sector.
211. OTP has demonstrated that the deferred Schedule 16
and 17 costs of $292,895 are appropriate for recovery.
A.
Wholesale
Margins Benefits during the Deferral Period.
As shown
on …Table 1, on page 8 of my direct testimony,[280]
retail customers received a significant benefit from asset-based margins. That table shows that we shared those
revenues by using them to allow sufficient earnings to avoid a rate increase as
early as 2003. If we had directly paid
those revenues to the ratepayers, we would have needed an increase in base
rates by an equal amount.
This point
is easily demonstrated by comparing our revenue requirement when asset-based
margins are used as a credit to base rates compared to our revenue requirement
if asset-based margins are passed through the FCA, or fuel clause
adjustment. Our initial revenue
requirement was 14.5 million based on sharing the margins through the FCA. That revenue requirement is reduced to 8.7
million when asset-based revenues are shared as a credit to base rates.
In either
case asset-based margins are shared with ratepayers. But when they are passed through directly to
payers [sic] instead of as a credit to base rates, these base rates need to be
increased.[281]
Mr.
Brause further explained:
[B]eginning
with 2003 we likely would have been in for a rate case.
Q. … With margins, wholesale
margins, the Company earned, if I’m correct 10 percent in 2006?
A Correct.
Q. What would they have earned without
margins in 2006?
A A little less than 7 percent.
Q. In your opinion was the
Company sharing margins with ratepayers in 2006?
A. Absolutely.
Q. And why is that?
A. Because the customer did
get the benefit of that. Had we had
returns above 12 percent, then I can say that we were sharing it with the
shareholder.[282]
Using the volumetric allocator, OTP charged regulated
costs to the non-asset based margin activity.[283] OTP maintains that this practice had the same
effect as a credit to the base rate revenue requirement of a portion of the
non-asset based margins. OTP asserted
that this practice reduced the base rate revenue requirement, thus improving
earnings and reducing the need for a rate adjustment.
214. The Department maintained that OTP’s assertions were
“speculative and conclusory, yet unsupported . . . . ”[284] The Department noted that OTP never decreased
its rates during this period to pass through any margins from asset-based
sales.[285] The Department strongly disagreed with OTP’s
conclusion. The Department noted that OTP’s
calculation of its revenue requirement in its jurisdictional reports for the
years between rate cases have not been audited to the degree that rate cases are
audited.[286]
215. The Department asserted that OTP’s retention of
asset-based margins did not defer the need for a rate increase. Rather, the Department contended that its
recommendation and the Commission’s Order in the Hotline Complaint Docket required OTP to file the current rate
case.[287] The Department noted that OTP experienced problems
with its allocations, an Allowance for Funds Used During Construction (AFUDC)
correction and affiliated-interest concerns, noted in the Hotline Complaint Docket.[288] For
these reasons, the Department asserted that OTP’s need to file a rate case
during the years 2003-2007 was not deferred due to the impact of asset-based
margins.[289]
B.
Appropriate
Share of Schedule 16 And 17 Costs to Allocate to Wholesale.
217. The Department’s position, that deferred Schedule 16
and 17 costs should not be recovered, is
premised on the argument that the “wholesale sector reaped significant profits
gained through MISO Day 2.”[290] OTP noted that 40 percent of the Schedule 16
and 17 costs were allocated to wholesale asset-based and non-asset based
margins.[291] Only the portion of Schedule 16 and 17 costs
allocated to retail were deferred for recovery in retail rates. The methodology used by OTP for allocating
MISO costs has been reviewed by the Department in a number of dockets without
challenge, most recently in Docket E017/M-05-284, and no challenge to that
methodology has been raised in this proceeding.
218. OTP proposed that its annual incentive compensation
be based on a 5-year average payout level, subject to a cap based on 25% of the
individual employee’s base compensation.[292] The Department opposed the Company’s
proposal, initially recommending that: (i) annual incentive compensation
be adjusted to remove the results of all asset based margins and ten percent of
non-asset based margins; and (ii) a refund mechanism be adopted. The Department also recommended that a 25%
cap be applied to incentive compensation paid to the Company’s employees who
conduct purchases and sales of wholesale power.[293]
A.
Incentive
Compensation Levels.
221.
A 2005
Towers-Perrin study showed that the OTP’s total cash compensation was 4% below
the market rate for a broad range of non-executive positions.[294] A 2007 Towers-Perrin study showed that total
cash compensation of Company executive positions was 21% below the market
median.[295] OTP relied on this information to assert that
the annual incentive compensation proposal, with the cap based on 25% of each
employee’s base salary, was reasonable.
OTP maintained there was no evidence that its approach would lead to
inclusion of excessive levels of compensation costs in rates.
222.
OTP maintained
that its compensation proposal was needed to provide adequate compensation in
order to attract, motivate, and retain talented employees. OTP maintained that this is needed to provide
high quality service to customers. To
obtain such employees, OTP asserted that it must offer a competitive total
compensation package.[296] OTP maintained that under-funding its
compensation packages would impede the OTP’s ability to attract, motivate and
retain employees.[297] OTP described its
annual incentive compensation plan is well balanced and consistent with
incentive compensation plans that have been approved by the Commission.[298]
223. OTP and the Department agreed on the
overall method to include the effect of asset-based wholesale revenues;
however, they differed on the amount to be credited to the base rate revenue
requirement.[299] The Department recommended that all asset-based
wholesale margins and ten percent of non-asset based wholesale margins be
removed from the incentive compensation calculation. These amounts would be deducted from the basis
for calculation of annual incentive compensation through a pro forma
calculation.[300] That recommendation was based on the belief
that this case would fundamentally change the manner in which the Company’s
earnings were calculated for determining the financial elements of its annual
incentive compensation payments.
224. The Department recommendation is based on the belief
that inclusion of asset based margins in regulated rates (on a going forward
basis after this rate case) will represent a fundamental change.[301] OTP maintains that the Department’s position
is not correct in two respects. First, OTP
has previously included all its asset based margins in its regulated earnings
and in its calculations of earnings under its annual incentive compensation
plans.[302] Second, the Department’s calculation is
inconsistent with the Department’s own recommendation to preserve the current
approach to asset based margins, under which both asset based revenues and
costs are included in the determination of the base rate revenue requirement.[303]
225. OTP has consistently included asset-based margins in
its regulated income, including all years from 2002 through 2007.[304] The Department acknowledged that there was no
basis to dispute OTP’s position that it had consistently included all asset-based
margins in its determinations of earnings in 2002 through 2007.[305] The Department also acknowledged that the
continuation of this practice after this rate case eliminated the basis to
believe that any material change would occur.[306] OTP maintained that the Department’s
calculation relied on a mistaken belief that only the 1987 level of asset based
margins ($739,000) had been included in determining earnings of OTP (for both
reporting and incentive compensation calculations).[307]
2. Implicit
Assumptions Regarding OTP’s Financials.
226. OTP maintained that the Department’s pro forma
calculation necessarily rests on the unstated premise that the Company’s
management would have allowed very substantial reductions in its ROE from 2002
through 2006 without taking action to correct that situation.[308] OTP asserts that it would not have allowed
such a substantial reduction in ROE to go uncorrected for any substantial
period of time, and it would have sought a general rate increase but for the
presence of earnings from wholesale margins.[309]
227. OTP maintained that the pro forma and actual ROEs for
the Management Plan would have been as follows:[310]
|
Year |
Actual ROE (per calculation in the Management
incentive plan) |
Pro forma ROE (calculated per Department
parameters) |
|
2002 |
12.69% |
11.23% |
|
2003 |
12.68% |
10.07% |
|
2004 |
12.16% |
9.80% |
|
2005 |
10.83% |
7.47% |
|
2006 |
10.49% |
7.57% |
The pro forma and actual ROEs for the Key Performance
Award plan (KPA) plan would have been as follows:[311]
|
Year |
Actual ROE (per calculation under the KPA incentive
plan) |
Pro forma ROE (per Department parameters) |
|
2002 |
12.69% |
11.23% |
|
2003 |
13.03% |
10.43% |
|
2004 |
12.31% |
9.94% |
|
2005 |
11.10% |
7.74% |
|
2006 |
10.50% |
7.59% |
228. OTP maintained that changing a single very
substantial historic event does not lead to a valid revision of historic events. OTP argued that corrective action would be
taken on response to changes, making unreliable the results of the single
revision.[312]
229. OTP also asserted that practical needs arising from
the employer perspective also demonstrate that appropriate action would have
been taken to prevent deterioration of earnings. OTP would not have afforded inadequate
incentive compensation to its employees without taking appropriate action to
restore adequate compensation levels. For
example, OTP modified its incentive plans in 2007 to decrease the significance
of financial performance in order to provide a more reasonable opportunity for
payout levels than had occurred in 2006, which reflected adverse financial
performance.[313]
3. The Impact of the Department’s ROE Recommendation on Pro Forma
Calculations.
230. The Department’s pro forma calculations, which were
intended to provide results representative of the future, rest on assumed
average ROEs of 9.00% to 9.15%.[314] In performing its pro forma calculations, the
Department ignored the 10.71% ROE that it initially recommended, which was
increased to 10.91%.[315] The assumed average ROEs of 9.00% to 9.15% do
not provide reasonable estimates of the results of future operations.
C.
Incentive Plan
Recommendation.
232.
OTP included
$568,673 as incentive compensation in its test-year revenue requirement.[316] The Department
recommends that incentive compensation that is included in base rates but is
not paid to OTP’s employees should be refunded to ratepayers. Each of OTP’s
incentive compensation plans contains the provision, "The Company, by
written action of its President, reserves the right to amend or terminate this
Plan at any time."[317] This
provision allows OTP to stop incentive compensation payments to employees but
continue to recover costs from ratepayers. The Company has not provided a logical
rationale for why such a regulatory refund mechanism is unreasonable. OTP
should be required to refund to ratepayers incentive compensation that is
included in rates but not paid to employees. A refund mechanism for incentive compensation
would be consistent with Commission precedent. The Commission in stated:
In the original Order, the
Commission expressed strong disapproval of the Company’s retention of the right
not to make incentive payments earned under the plan. The Commission continues
to view this as an inappropriate transfer of risk from shareholders to
ratepayers and as inconsistent with the test year concept on which rates are
based. The Commission will therefore require the Company to record all earned
but unpaid incentive compensation recoverable in rates under this Order for
future return to the ratepayers. This will adequately protect ratepayers’
interests and prevent erosion of the test year concept.[318]
233.
This approach
was followed in the 2005 Xcel Energy Rate
Case where the Commission ordered:
The Commission concurs
with, accepts, and adopts the ALJ’s recommendation on this issue, which was to
cap individual incentive compensation payments at 25% of an employee’s base
salary; to base total, company-wide incentive compensation on amounts actually
paid out between 2002 and 2005; and to continue the tracking and refund
mechanism established in the Company’s 1992 rate case.[319]
The Commission finds that
the Company’s proposed level of incentive compensation in this proceeding is
reasonable and will approve it. The Commission also adopts the ALJ’s finding
and will require Xcel to refund amounts included in the test year for incentive
compensation that were not actually paid.[320]
235.
The Department continues
to recommend that OTP be required to refund to its customers incentive
compensation that is unpaid but included in rates. OTP maintained that a refund mechanism is
unnecessary. OTP noted that the refund
mechanism was applied only to Xcel Energy and has not been applied to other
utilities in
VII.
fas 106
transition costs.
237. OTP requested recovery of the
238. The Company’s FAS 106 Transition Costs began with a
$17,618,642 balance in 1993 that was subsequently adjusted to $14,964,000, with
a 20-year amortization of $748,200 per year.
The Department did not dispute the calculation of the $748,200 annual
amount.[325]
239. The Department objects to the inclusion of the FAS
106 Transition Costs because: (i) the Department asserts that no amortization
of any FAS 106 Transition Costs could occur unless the Company filed a rate
case or other request to establish an amortization account for FAS 106
Transition Costs within in three years of the Order Adopting Accounting
Standard; and (ii) the Company’s FAS 106 Transition Costs were recorded in
1993.[326]
240. OTP maintains that if the Department is correct in
the contention that OTP Company had no right to establish an amortization
account for the FAS 106 Transition Costs, there should be no reduction to rate
base as a result of the amortization of FAS 106 Transition Costs. That reduction amounts to $5,429.751. The Department does not dispute this
relationship and conclusion.[327] The net result of disallowing the
241. The Order Adopting Accounting Standard distinguished
between: (i) the basic amortization of FAS 106 Transition Costs; and (ii) the
possibility of deferred accounting for 3 years of the amortization of
those costs. OTP maintains that the
order allowed, but did not require, deferred accounting of FAS 106 transition
costs for three years.[329]
Amortization
means the gradual extinguishment of an amount in an account by distributing
such amount over a fixed period, over the life of the asset or liability to
which it applies, or over the period during which it is anticipated the benefit
will be realized. (18 C.F.R. Part 101
definitions.)
OTP contrasts this with deferred accounting, which is
a regulatory construct under which a cost is accumulated for the period of the
deferral for later recognition and recovery.
Typically, deferred accounting involves accumulation of an annual
expense for a period of time (into a regulatory asset account) for subsequent
recovery over a reasonable period (amortization).[330]
The
Commission will therefore adopt SFAS 106 accrual accounting for
IV. Implementation
of SFAS 106.
As
discussed previously, the change from pay-as-you-go accounting to the accrual
method for OPEBs may raise utility revenue requirements. If utilities were required to recognize the
difference at once, the accounting change could force many utilities to file
general rate cases in order to adjust their revenue requirements. The
Commission will therefore allow utilities to defer the increased cost created
by the change to SFAS accounting.
The Commission will limit the time for such deferred accounting for each utility to a period of three
years beginning January 1, 1993, or until the issue date of the Order which
sets final rates following a general rate case, whichever occurs first.[331]
244. OTP maintained that the first paragraph of the quote
addressed the treatment of the basic amortization of FAS 106 Transition
Costs. The second paragraph of the quote
addressed the possibility of deferral of three years of the annual
amortization. OTP argues that the purpose
of the three-year deferral period was to avoid the potential of several
utilities immediately filing rate cases, not to limit to three years recovery
of FAS 106 Transition Costs (which could be up to 30 years).[332]
The
Commission will clarify its September 22, 1992 Order to identify specifically
the treatment of deferred accounts beyond the three year period beginning January
1, 1993. If no rate case is commenced
within that three year period, a utility will not be allowed recovery of the
deferred amount.[333]
Ordering Clause 5 contains the same provisions and is
also limited in scope to the “deferred amount” and reads in part:
Deferred
accounting will be allowed for each utility for three years beginning January
1, 1993. If no rate case is commenced
within that three year period, a utility will not be allowed recovery of the deferred amount. If a rate case is filed within the three
years, the utility will be allowed to continue deferring OPEB expenses until a
final Order is issued in the rate case.[334]
246. OTP notes that the Commission has recognized that FAS
106 Transition Costs are an allowable cost of service, and it has permitted other
utilities to recover these costs.[335] OTP asserted that the approval obtained by
some utilities for amortization in matters filed before the Order Adopting Accounting Standards
shows that the there is no rigid application of the subsequently adopted
three-year limitation. OTP cites the 1992 Northern States Power Rate Case, where
the Commission stated:
In the FAS
106 situation, the Commission has always found that the payment of
Post-Employment Benefits Other than Pensions is a cost of service. A change in utility accounting, which results
in a transition obligation, does not mean that these costs should be
disallowed. (Emphasis added.)[336]
1.
Recording Of FAS
106 Transition Costs.
248. All the cases cited by OTP were decided before the Order Adopting Accounting Standards. OTP maintains
that the Commission’s adoption of FAS 106 for both accounting and ratemaking
purposes authorized up to a 30-year amortization period. OTP notes that other utilities continue to
recover their FAS 106 Transition Costs, which arose at the same time as the Company’s
FAS 106 Transition Costs.[337]
249. The Department maintains that OTP’s position is correct
only if the FAS 106 Transition Costs are initially appropriately included in
rate base. The Department contends that,
for ratemaking purposes, this rate case is the first time the Commission has
had an opportunity to decide whether OTP’s transition obligation should be
appropriately included in OTP’s rates. Since
OTP has not filed for deferred accounting with the Commission, the Department
contends that the transition obligation amount is not allowable in OTP’s rate
base. The Department contends that utilities
that decide to make such changes between rate cases without Commission approval
are always at risk for nonrecovery of costs in their next rate case proceeding.[338] Under the
Department’s approach there would not be a shift to increase the rate base by
$5,429,751 as OTP claims, but rather a reduction to rate base by the remaining
amount of the unauthorized, unamortized transition obligation.[339]
2. Effect on
Rate Base.
250. OTP maintains that disallowance of its amortization
of FAS 106 Transition Costs (at $748,200 per year for total Company) would
result in a $5,429,751 increase to the
251. OTP’s contention relies on the deferred costs being
allowable, despite the absence of approval of these costs by the Commission
under the terms of the Commission’s Order
Adopting Accounting Standards. OTP
argues that, if the FAS 106 Transition Costs are not allowed as part of FAS 106
costs, the rate base would need to be trued-up to match this change. The cumulative amount of the amortization of
the transition obligation through 2006 is $10,873,200 (with a
VIII.
pension, opeb
and medical expenses.
253. The Company proposed test year costs of $19,277,539
for Pensions, OPEBs, and Medical/Dental (collectively “Benefit Costs”), which
was $414,984 below the 2006 actual levels
of $19,692,523.[342] The Company proposed that:
(i) the
test year expense levels for Pension and OPEB expenses be based on the
actuarial studies of determining 2007 costs; and
(ii) the
test year expense levels for Medical/Dental be based on actual data from
January 2007 through July 2007, with the remainder of 2007 projected.
Overall, the Company’s Benefit Costs have
increased significantly from 2003 to 2007:[343]
|
Year |
Total Amount |
Change ($$) |
Change (%) |
|
2003 |
$14,675,355 |
|
|
|
2004 |
$16,318,622 |
$1,643,267 |
11.2% |
|
2005 |
$18,356,668 |
$2,038,046 |
12.5% |
|
2006 |
$19,692,523 |
$1,335,895 |
7.3% |
|
2007 (est.) |
$19,277,539 |
($414,984) |
(2.1%) |
1.
The Company’s
Projection and Actuarial Studies.
254. The Company used: (i) the actuarial determination of
Pensions and OPEBs for 2007 that was prepared by Mercer Human Resource
Consulting, Inc. (“Mercer”); and (ii) the actual and projected Medical/Dental
expenses for 2007.[344] The Department reviewed the Mercer actuarial
studies and did not dispute the accuracy or reasonableness of the Mercer studies.[345] The Department did not dispute the accuracy
of the Company’s projection of Medical/Dental expenses for 2007.
255. Mercer performs annual analyses of the Company’s
Pension and OPEB expenses. Annual
actuarial analyses of Pension and OPEB obligations are performed to satisfy
legal requirements arising from several sources, including: (i) the Employee
Retirement Income Security Act; (ii) the Pension Benefits Guarantee
Corporation; (iii) the Internal Revenue Service; and (iv) the Securities
Exchange Commission.[346]
256. Mercer’s estimate of $4,232,101 for 2007 Pension
Expenses that the Company has proposed are based on FAS 87 expenses for 2007
and are $1,200,861 (22%) lower than
actual FAS 87 expenses for 2006.[347] The Mercer estimate reflected a number of
specific factors, which are appropriate for calculation of 2007 pension
expenses and are consistent with FAS 87.
257. The Mercer estimate is based on the Company’s
demographics and its related business environment. These demographics and business environment
factors include: (i) an updating of mortality tables in 2005; (ii) cash funding
of approximately $4 million in each of 2005 and 2006; (iii) the current
interest rate environment; (iv) recent legislation, including the Pension
Protection Act of 2006; (iv) the soft freeze of the Company pension plan that
occurred in 2006; and (v) the Company’s current union labor agreement.[348] OTP maintains that these factors demonstrate
why a 5-year simple average is an inappropriate and inaccurate basis to
estimate Pension expenses.
258. Mercer’s estimate of $3,321,412 for OPEB expenses
that the Company has proposed are based on FAS 106 expense levels for 2007 and
are $186,056 (5.9%) higher than actual FAS 106 expenses for 2006.[349] The actuarial model that Mercer used to
calculate the FAS 106 OPEB expense reflects changes in demographics and
business environment.
259. Mercer’s actuarial calculations have changed to
reflect: (i) annual review of discount rates and trends in medical expenses;
(ii) new demographic information such as the relevance of marital status in
actuarial calculations, which occurred in 2003; (iii) modification of the
turnover rate and the updated mortality tables, which occurred in 2005; (iv)
Company policy changes, like the increased cap on Coyote Station employees,
which was implemented in 2003; and (v) legislative changes, such as the
implementation of the Medicare Prescription Drug Improvement Act of 2003, which
introduced the Medicare Part D subsidy (that caused a decrease in OPEB expenses
in 2006).[350] OTP maintains that these are significant
factors which demonstrate that a 5-year simple average is an inappropriate and
inaccurate basis to estimate OPEB expenses.
260. OTP based its proposed Medical/Dental expenses on actual claims (expense) data through June 2007, trended to
the end of 2007.[351]
Medical/Dental expenses for
2003-2006 are as follows:
|
Year |
Expense |
Change from Prior Year ($) |
Change from Prior Year (%) |
|
2003 |
$8,666,479 |
|
|
|
2004 |
$9,741,825 |
$1,075,346 |
12.4% |
|
2005 |
$9,448,573 |
($293,252) |
(3.01%) |
|
2006 |
$11,124,205 |
$1,675,632 |
17.7% |
|
2007 (est.) |
$11,724,026 |
$599,821 |
5.4% |
OTP noted that only 2005 showed a slight $293,252
decline (3%) from the prior year.[352] In this context, the Company’s estimate of a
modest increase in 2007 was well founded.
The Department did not identify any inaccuracy in OTP’s estimates.
2. The
Department’s Recommendations.
261.
The Department
recommended Benefit Costs of $17,664,141, based on a 5-year simple average of
data for 2003 through 2007.[353] The
Department recommendation was $1,613,398 below the Company’s proposal[354] and $2,028,382 below the actual 2006 levels
([$19,692,523 actual 2006] - [$17,664,141 Department recommendation]). The Department recommendation would
substantially change expense levels for each of the elements of Benefit Costs:
(i) decreasing Medical/Dental
expenses by $1,583,004; (ii) decreasing Pension
expenses by $799,534; and (iii)
increasing OPEBs by $769,141.[355]
262.
The Department’s
argument is premised on two claims: (i) that costs have historically
fluctuated, which makes averaging a better approach; and (ii) that the
Commission took a similar approach to averaging in the 2003 IPL Rate Case.[356]
265.
OTB notes that pension
costs have also increased significantly from 2002 through 2007 as follows:[357]
|
Year |
Amount |
Change
from Prior Year ($) |
Change
from Prior Year (%) |
|
2003 |
$1,434,687 |
|
|
|
2004 |
$1,875,126 |
$440,439 |
30.7% |
|
2005 |
$4,187,960 |
$2,312,834 |
123.3% |
|
2006 |
$5,432,962 |
$1,245,002 |
29.7% |
|
2007 |
$4,232,101 |
($1,200,861) |
(22.1%) |
267.
The Department
has proposed a Pension expense of $3,432,567, which is a further reduction of
$799,534[358] from the Company’s proposed Pension expense. The effect is also a $2,000,395 (37%)
reduction from the actual 2006 level.[359] Using a
five-year average of Pension expense is a backward-looking model that
implicitly assumes no fundamental trends or changes, and which does not
properly reflect new information. The
Department provided no evidence or analysis to support the preference for an
arbitrary averaging that includes clearly non-representative data, such as the
very low Pension expense levels of 2003 and 2004, in place of the results of
actuarial studies.
268.
OPEB expenses
have decreased since 2003, as follows:[360]
|
Year |
Amount |
Change from Prior Year ($) |
Change from Prior Year (%) |
|
2003 |
$4,574,189 |
|
|
|
2004 |
$4,701,671 |
$127,482 |
2.8% |
|
2005 |
$4,720,135 |
$18,464 |
0.39% |
|
2006 |
$3,135,356 |
($1,584,779) |
(33.6%) |
|
2007 |
$3,321,412 |
$186,056 |
5.9% |
269.
In contrast to
the foregoing data, the Department recommendation is to increase the 2007 estimate by $769,141[361] with the result being OPEB costs of $4,090,553.[362] This is also
a $955,197 (30%) increase from the actual 2006 level.[363]
270.
The Department
provided no analysis of OPEB expenses[364] and no criticisms of the Mercer analysis.[365] A review of
the Department testimony shows no assertion of inaccuracies in the Company’s
determination of 2007 Medical/Dental expenses.
The Department relied on OTP’s 2007 data as part of its 2003-2007
five-year average.[366]
271.
The Department's
approach was to determine a reasonable level of expense attributable to
Levelizing is standard
ratemaking treatment of anomalies in test year expenses, and the possibility
that the timing of the Company’s next rate case may work to its disadvantage in
regard to this one test year expense does not justify abandoning normal test
year procedures for dollar for dollar recovery.[368]
272.
If the
Commissioner chooses to use levelizing in this proceeding, subtracting the
average amount from OTP’s proposed $19,277,539 results in a decrease of
$1,613,398 in the test year amount.[369]
3. Recent
Commission Decisions.
273. In the 2005
CenterPoint Energy Rate Case,[370] the ALJ
recommended acceptance of the Department position, but the Commission rejected
the ALJ recommendation, saying:
The
Commission believes that the best
predictor of test-year pension expenses should be used. In this case, the pension expenses proposed by
CenterPoint were actuarially determined …, using CenterPoint’s participant
demographics and actuarial assumptions consistent with those used by its
parent, CPE. The pension costs were
computed following the principles required by Financial Accounting Standards
(“FAS”) no. 87, “employers’ accounting for pensions.”[371]
IX.
Corporate Cost
Allocations.
A.
OTP’s Proposed
General Allocator.
1) Tariffed
rates shall be used for tariffed services provided to nonregulated activity.
2) Costs shall
be directly assigned whenever possible.
3) If costs
cannot be directly assigned, they shall be allocated based on an indirect
cost-causative linkage to another cost category or group of cost categories for
which direct assignment or allocation is available.
4) When neither
direct nor indirect cost causation can be found, the costs are to be allocated
using a general allocator.[372]
The Commission also adopted a default general
allocator that uses the ratio of all expenses directly assigned or attributed
to regulated and unregulated activities, excluding the cost of fuel, gas,
purchased power, and the cost of goods sold.[373]
The
Commission understands that utilities differ in many essential respects,
including their participation in affiliated operations. The Commission believes that the hierarchical
principles offer sufficient flexibility for each utility to develop appropriate
allocation methodologies based on the principles.[374]
… its cost
allocation principles produce similar results as would allocations following
the recommended cost allocation principles,
* * *
or the
public interest is better served by another method.[375]
279. On the subject of allocation principles, the
Commission’s Docket 1008 Order, states in part:
Should a
utility wish to base its cost separations on different principles, the burden
of proof would be on that utility to prove that its cost allocation principles
arrive at fully allocated costs, free of any cross-subsidization. The utility would have to show that the goals
of fully allocated costing, as expressed in this and other Orders, are fully
realized. The utility would have the
burden of demonstrating that it considered all of its costs and that they are
allocated to share burdens and benefits equitably between the regulated and
nonregulated operations.[376]
280. OTP proposes changing Commission’s methodology with
respect to the general allocator. Rather
than use the default allocator of expenses, OTP uses a general allocator
comprised of three equally weighted components of revenues, assets and labor
dollars.[377]
281. Ms. Brutlag testified that because of the diverse
business activities of OTP’s unregulated affiliates, using expenses as the only
allocator would not provide reasonable results.
A substantial portion of labor costs for the utility is
capitalized. In comparison, Otter Tail
Corporation’s diversified businesses capitalize almost none of their labor
costs. The default allocator, which uses
only expenses, does not reflect this circumstance. Otter Tail Corporation’s business operating
margins range from 0.8 percent to 16.4 percent of revenue. OTP maintains that this variation shows that expenses
relative to revenues vary significantly.[378] Some of OTP’s subsidiaries have significant
assets, while others have few assets; some are high revenue, low margin
businesses, while others are low revenues but high margins; and some are more
labor intensive businesses. OTP
contended that using the three components of revenues, assets, and labor,
recognizes this diversity. OTP
maintained that its proposed allocation formula made up of these three major
components is expected to have less unnecessary volatility than simply using
expenses for the allocation.[379]
282. In its last rate case, Xcel Energy used a general
alternative with three factors that is the same as OTP’s, except that it used
employee count rather than labor dollars.[380] OTP used labor dollars instead of employee
count because the information was reliable and easily obtained without
additional administrative work.[381]
283. The 1008 Docket’s default general allocator allocates
$1,524,387 (28%) of corporate costs to OTP in the test year, while OTP’s
proposed general allocator would allocate $2,098,794 (38%) of corporate costs
to OTP. The difference between these two methods is $574,407. The Department contends that this difference
demonstrates that the two methods clearly do not provide similar results.[382]
284. The 1008 Docket default general allocator is computed
using the ratio of all expenses directly assigned or attributed to regulated
and non-regulated activities, excluding the cost of fuel, gas, purchased power,
and the purchased cost of goods sold.[383] The Department contrasted the accepted
allocator elements to OTP’s proposed general allocator, which is comprised of
only revenues, assets and labor.
285. The Department also noted that OTP’s alternative
increased the revenue requirement by $287,204.[384] The Department distinguished Xcel Energy’s
general allocator based on the fact that, for Xcel Energy, the alternative
general allocator resulted in a lower revenue requirement.[385]
286. OTP asserted that whether OTP’s general allocator
shares costs equitably should not be determined based on which methodology assigns
the least cost to OTP. OTP asserts that
the appropriate standard is whether there is an equitable sharing of
costs. OTP had 55 percent of the
consolidated corporation’s assets, 50 percent of the consolidated corporation’s
income before income taxes, and paid 30.5 percent of the corporate management
costs.[386] Incorporating the default allocator into the
allocation process would have allocated 29 percent of all corporate costs to
OTP in 2006.[387]
287. The OAG maintained that if the Commission’s
requirement under Docket 1008 is that an allocator should produce similar
results to the default allocator, then utilities should “just use the 1008
method.”[388] The OAG also argued against each of the three
components of the OTP General Allocator.
The OAG opposed using assets because utilities are asset heavy, with 54
percent of the assets residing in the utility.[389] Reliance on labor cost was opposed because
different companies have different labor intensity.[390] The OAG expressed concern about using revenue
as a factor, since some business operations have higher profit margins than
others.[391]
288. The OAG argued that OTP’s methodology could lead to
volatile results as unregulated businesses were acquired or sold.[392] OTP contended that volatility was more likely
under the default general allocator than under its three component allocator. OTP maintained that its allocator is influenced
differently by different types of businesses providing stability rather
fluctuations.[393]
B.
OTP’s Prior
Financial Reporting.
290. The OAG alleged that that it had “confirmed that
inaccurate financial reporting has been the norm for OTP in the past.”[394] OTP contends that the basis for this claim is
OTP’s prior use of a different general allocator than was used in the test
year. OTP pointed out that utilities are
allowed to use a general allocator that is different from the default general
allocator under that standards set out in the Commission’s 1008 Docket Order. The propriety of OTP’s general allocator was
at issue in the Hotline Complaint Docket. In that matter, OTP noted that, using the general
allocator in effect (prior to the Commission’s provisional approval of the
current general allocator), 37.4 percent of total corporate costs were
allocated to OTP in 2006.[395] An allocation of 37.4 percent of the corporate
costs, when the utility had 55 percent of the consolidated corporation’s
assets, and 50 percent of the consolidated corporation’s income before income
taxes, does not support the OAG’s claim of “inaccurate financial reporting.” The change of an allocator in response to a
Commission proceeding does not, without more, support a claim that there has
been “inaccurate financial reporting.” No
evidence has been introduced in this proceeding that OTP has inaccurately
reported its financial information.
C.
Whether Costs
Have Been Properly Allocated To Unregulated Operations.
|
2006 Corporate costs allocated before adjustments |
7,184,242 |
|
Adjustment for general allocator agreed to in Hotline
docket |
(913,374) |
|
Corporate costs only adjusted for general allocator |
6,270,868 |
|
Wage increase |
153,459 |
|
25% bonus cap |
(349,541) |
|
Net of two additional adjustments |
(196,082) |
|
Corporate costs allocated to utility for test year |
6,074,786 [396] |
Line 3 in the above table is the
$6,270,868 amount found in the work papers and relied upon by the OAG for its
claim. Ms. Brutlag’s Direct Testimony
differed by $9 from the amount reflected in the last line of the above
table. The $9 is apparently the result
of a typographical error in Ms. Brutlag’s Direct testimony where the 2006
Corporate costs allocated before adjustments were reported as $7,184,233
instead of $7,184,242.[397]
293.
OTP
has shown that its allocation system produced appropriate results.
D.
Calculating the
25 Percent Cap on Incentive Compensation.
|
OAG Method |
OTP Method |
|
$200,000 salary |
$200,000 salary |
|
$100,000 bonus |
$100,000 bonus |
|
$300,000 total |
$300,000 total |
|
times .3 allocation |
less $75,000 ($100,000
less $25,000 allowed) |
|
$90,000 |
225,000 |
|
less 22,500 (.3 times
the excess $75,000) |
times .3 |
|
$67,500 costs to OTP |
$67,500 costs to OTP |
297. The OAG claimed that two legal invoices provide “an
example of improper allocations for the test year.” [398] OTP noted that the invoices were legal
expenses, not allocated expenses. The
expenses were directly incurred by OTP, not OTC.[399] The allocation process is not relevant to
this claim.
298. OTP had declined to provide its actual invoices based
on the attorney client privilege. As
agreed to at the evidentiary hearing,[400] OTP
provided a trade secret summary of the purposes of the legal work and explained
why the expenses were reasonable utility expenses.[401] The OAG did not identify a particular reason
for disallowance of these expenses. The
OAG maintained that the description of the expenses provided in the summary
does not justify cost recovery.
299. OTP has demonstrated a sufficient basis for recovery
of these direct expenses.
F.
Proposed Workgroup
to Evaluate OTP’s Cost Allocations.
300. The OAG advocated creation of a work group to develop
a new cost allocation manual for OTP.
The OAG maintains that such an approach is needed due to the deficiencies
that have been identified in this proceeding.[402]
303. OTP allocated energy costs using kWh sales for both
jurisdictional cost of service study (“JCOSS”) and class cost of service study
(“CCOSS”) purposes. Enbridge and the MCC
advocated the use of an E8760 allocator, which allocates energy costs on a per
kWh basis with adjustments by class weighting factors to reflect differences in
class load patterns and hourly marginal energy cost.[403] In the absence of an E8760 allocator, Mr.
Erickson created a “hybrid 8760” allocator.[404]
304. The name (E8760) reflects that there are 8760 hours
in a year and that the different energy costs in each hour would be used in
developing a different energy factor for each customer class. Xcel Energy used an E8760 allocator in its
CCOSS in its most recent electric rate case, Docket No. E002/GR-05-1428.[405] For jurisdictional purposes, Xcel Energy
continued to allocate costs using its previously approved E20 energy allocation
methodology.[406] Similarly, while Minnesota Power developed an
E8760 allocator for retail rate design purposes, in Docket No. E015/M-07-1430,
Minnesota Power used total energy sales adjusted for losses for purposes of its
jurisdictional allocator.[407] Dr. Ouanes supported the use of the E8760 methodology in OTP’s next rate case,
for CCOSS purposes, stating: “the E8760
allocation factor would more accurately reflect costs imposed on customer
classes on OTP’s system than the E1 and E2 [jurisdictional] allocation factors
proposed by OTP.”[408]
305. OTP proposed studying the implementation of an E8760
factor for use in its CCOSS, presenting the results of such a study and
potentially recommending implementation of an E8760 allocator for use in its
CCOSS in its next rate case.[409] OTP proposed this approach for the following
reasons:
Developing
an E8760 factor for OTP’s
306. In the absence of the detailed usage and cost
information needed to develop an E8760 factor, Mr. Erickson created a different
energy allocation factor using only limited information for Enbridge. Based on his “hybrid E8760 factor,” Mr. Erickson proposed shifting $1,475,210 in
costs from
307. The only load data used by Mr. Erickson was for
Enbridge. OTP noted that Enbridge, while
a large customer, accounts for only 20 percent of OTP’s
308. OTP contended that customers in
Q. …[O]n page 4
of Mr. Erickson’s surrebuttal, Enbridge’s witness has a rate table, and why are
the
A. Those rates
are from the EEI average, a rate survey for the period ended June 30,
2007. The comparison is the average
price paid, not the actual rates paid.
The average prices are lower in North and
309. OTP argued that the wider controlled service rate use
in
310. Mr. Schedin testified that while the differences in
demand and energy between the states were not significantly different, the
E8760 allocator would still be useful for class allocation purposes in the
CCOSS stating: “that’s where the E8760 allocator is most important, comparing
the classes.”[416]
312. The Department and OTP agreed that Mr. Erickson’s
approach did not provide useful results.[417]
XI.
CLAIMED
Adjustment FOR Losses.
314. Mr. Erickson proposed a new financial adjustment of
$147,000, asserting that OTP had improperly allocated losses because: (1) OTP
had not prepared a new loss study to match the MISO Day 2 market treatment, and
(2) because Enbridge now takes service at 115 kV.[418]
315. OTP responded that it does not directly allocate
losses. Rather, OTP uses losses in the
calculation of energy factors, stated as a percentage. These energy factors are not used to recover
losses. Mr. Beithon explained that an
updated loss study would not have a material impact on the cost allocations
between jurisdictions because a change in loss levels does not change the
relationship between the allocation factors.[419] An updated loss study would uniformly
increase or decrease each of the allocation factors by the same
percentage. That would result in the
allocation factors retaining their existing relationships and the resulting
allocated costs would not change materially.
316. Enbridge’s adjustment was based on the assumption
that OTP had allocated losses at the same percentage for its pipeline load as
was used in the 1986 rate case. At the
time of the 1986 rate case, OTP owned the transformers used to serve its pipeline
customers. Subsequently, Enbridge
purchased the transformer from OTP.
Because the transformer is now owned by Enbridge, the losses associated
with the transformer are no longer treated as losses on OTP’s system. OTP adjusted the
losses to reflect Enbridge’s ownership of its own transformer. The losses assigned to the pipeline group in
OTP’s prior rate case were reduced from 6 percent to 4.25 percent.[420] OTP has other pipeline customers besides
Enbridge and, consequently, the losses associated with Enbridge were lower than
4.25. While Enbridge is not responsible
for losses related to the transformer, it is responsible for its proportionate
share of transmission losses. In the
past, losses for 100 kV and above facilities were recovered through bilateral
agreements, now they are recovered through MISO. The loss payment mechanism has changed under
MISO for larger transmission facilities, but the payment for losses has not
changed, and OTP still pays for the losses attributable to Enbridge. Enbridge should still be responsible for its
proportionate share of losses.
317. Mr. Erickson’s adjustment is based on limited
information for the 20 percent of OTP’s
318. For all of the forgoing reasons, Enbridge’s proposed
loss adjustment should be denied.
319. Enbridge proposed a $457,566 adjustment to the D-1 allocation
factor to reflect an error made by OTP in the treatment of interruptible
loads. OTP agreed to the need for the
adjustment but determined that there had been an error in the original
calculation of the D-1 factor for Enbridge’s load. When the correction to the original D-1
factor was made, the net adjustment became $261,210. Enbridge stated in its Initial Brief
that: “To date, Enbridge has not been
provided any work-papers to support Mr. Beithon’s amendment, and we
cannot, therefore, agree to the OTP adjustment.”[421]
320. Mr. Beithon explained his adjustment to the D-1
factor in his surrebuttal testimony. [422] Enbridge provided no evidence that the
adjustment made by Mr. Beithon is incorrect.
Enbridge cross examined Mr. Beithon on the
reasons for the adjustment, obtaining clarification of the need for the change.[423] OTP provided sufficient evidence to explain and
support its adjustment.
XIII.
Proposed FCA
Matching Adjustment.
325. OTP pointed out that the lack of correlation between
the base cost of energy and Mr. Erickson’s lag adjustment is demonstrated when
Mr. Erickson’s methodology is used to calculate a “lag” adjustment after the
Department’s AAA adjustment is made to the base cost of energy rate. The Department’s adjustment reduces both fuel
revenues and fuel expense by $683,983 and, consequently, has no impact on the
revenue requirement.[424] That adjustment, however, reduces the base
cost of energy to $0.025668. When that
change in the base cost of energy is flowed through Mr. Erickson’s methodology,
his adjustment is reduced from $529,613 to $210,193. OTP maintained that a change in the base cost
of energy, having no impact on the rate case revenue requirement, should not
cause more than a 60 percent reduction in Mr. Erickson’s FCA lag adjustment.
326. OTP contends that if this “lag” adjustment was
appropriate, it would have been appropriate in every electric and natural gas
rate case since the FCA and PGAs were implemented at the inception of
regulation in the 1970s. Mr. Erickson
asserted that the FCA lag was eliminated the 1994
327. Enbridge argues that OTP’s position on this issue is
inconsistent with its own Revenue Recognition Accounting.[425] This appears to be a reference to OTP’s 2006
Annual Report in which there was a footnote stating that “Revenue is accrued
for fuel and power costs incurred in excess of amounts recovered in base rates,
but not yet billed through the fuel clause.”
Mr. Beithon explained that this is a financial reporting reference to
OTP’s FCA true-up mechanism.[426] The true-up mechanism annually adjusts
revenues to match expenses. A number of
factors can cause a mismatch between revenues and costs, but OTP maintains that
none of those reasons are due to a lag.[427] In some years, OTP will recover additional
revenues through the true-up process, while in others (including, OTP noted,
the current year) it will be providing a refund.[428] OTP maintained that, under Enbridge’s
argument, OTP would currently be entitled to an increase in its revenue
requirement.
329. OTP requested that $330,000 in economic development
expenses be included in revenue requirements.[429] OTP’s proposed economic development expenses
consist of $175,000 in labor costs, $20,000 in related expenses, a $35,000 loan
pool loss provision, and a new $100,000 community matching-grant component.[430]
330. Over the past five years, OTP has typically spent
about $250,000 annually on its
331. The Commission has allowed economic development costs
to be included in a utility’s revenue requirement where such development programs
are demonstrated to be cost effective.
The Commission declined to require that each program be determined to be
cost-effective on its own merits.
Finding that both ratepayers and shareholders benefited from such
programs, the Commission awarded 50 percent of the overall economic development
costs for inclusion in rates.[434]
332. OTP noted that its service area includes a very
sparsely populated region of
333. OTP noted that many of the small towns it serves are
experiencing population decline.[438] OTP maintained that a lack of job
opportunities contributes to this decline. Migration is occurring from the smaller towns
to larger communities in OTP’s service territory. Migration is also occurring from within OTP’s
service territory to areas outside Otter Tail’s service territory, such as the
growing Fargo-Moorhead,
334. OTP has had an active economic development program in
place for the last several years. OTP
partially credits the absence of any decline in total population across its
service territory to these efforts. OTP
noted that the population in
335. OTP intends its economic development efforts to
stabilize its communities by reducing intra-territory migrations and
out-migrations.[441] No party disputed that OTP’s economic
development efforts have been successful in saving and creating jobs throughout
its
336. OTP’s economic development efforts in 2006 included
44 projects throughout its
337. OTP noted that when its customers change locations
within OTP’s territory, OTP incurs all the costs of service at the new location
but does not avoid all the costs of service at the old location. This creates a duplication of costs of
providing electric service.[444] The duplicated (also known as “sunk”) costs
include costs related to delivery facilities, costs of line personnel and other
costs. In these instances of
intra-territory migrations, OTP does not avoid any costs of service, including
energy related costs or costs associated with transmission and generating
capacity, as those costs are still incurred to serve the customer at the new
location.[445]
338. OTP demonstrated that its economic development
proposal is cost effective in mitigating the waste associated with
intra-service territory migrations.[446] No party challenged OTP’s demonstration of
the cost-effectiveness of OTP’s program in mitigating the waste associated with
intra-service territory migrations.[447]
339. When OTP customers migrate to areas outside OTP’s
service territory (out-migration), OTP does not avoid all the costs of service
of the departing customers.[448] Just as for intra-territory migrations, the
sunk costs that are not avoided when customers out-migrate are those related to
delivery facilities, line personnel, and other costs.[449]
340. A benefit/cost ratio of 1.00 or more indicates the
proposed program to be cost effective.[450] The Department’s original cost effectiveness
analysis, performed for its direct testimony, showed a result of 0.91.[451] OTP pointed out that the Department had
assumed that all costs of services would be avoided when a customer
out-migrated.[452] The Department subsequently adjusted its cost-benefit
analysis using available cost information for OTP transmission and generating
capacity costs that demonstrated OTP’s proposed economic development program to
be cost effective, with a result of 1.19.[453] OTP also performed several sensitivity
analyses, all of which were above 1.00.[454] No other party attempted to evaluate the
program’s cost effectiveness.
341. The Department continued to argue that none of the
program’s costs should be included in OTP’s revenue requirements because it
believed that updated capacity cost information relating to the Big Stone II
project “may be large enough to make Otter Tail’s economic development program
not-cost-effective.”[455] The Department contended that OTP did not
adequately demonstrate that its economic development proposal is cost effective
with respect to out-migrations.[456] The OAG and AG Processing indicated their
support for this position, but did not provide independent evidence or
evaluations.[457]
342. The Department’s argument relied on an assumption
that out-migrations should be assessed in the same manner as conservation
programs, for which a cost-benefit analysis would include savings associated
with avoided transmission and generating capacity costs.[458] This argument was limited to an evaluation of
the program with respect to out-migrations.
The Department did not contest the cost-effectiveness of OTP’s program
with respect to intra-territory migrations.[459]
343. OTP has shown that equating out-migrations with
conservation and including such costs in the cost-benefit analysis is
inappropriate. Out-migrations do not
reduce the need for capacity additions.
The need for capacity additions is merely moved from one utility
territory to another.[460] This is a clear difference from conservation
programs, where the need for capacity is reduced by avoiding demand.
344. The OAG claimed that 50% of economic development
costs were disallowed in OTP’s last rate case and argued that 50% of OTP’s
current proposed economic development costs should be disallowed consistent
with Commission precedent.[461] The OAG is incorrect that 50% of OTP’s
economic development costs were disallowed in its last rate case. No economic development costs were disallowed
in that rate case.[462]
345. The OAG’s and AG Processing’s argument that 50% of
OTP’s economic development costs should be disallowed based on Commission
precedent ignores the Commission direction that 100% of such costs should be
allowed if a utility’s economic development program is demonstrated to be cost
effective.[463] As discussed above, OTP has demonstrated that
its economic development program is cost effective and, therefore, 100% of the
costs associated with that program should be allowed to be recovered in rates.
346. The OAG and AG Processing argued that Otter Tail Corporation’s
non-utility subsidiaries should share in the costs of OTP’s proposed economic
development program because they may benefit from such programs.[464] These arguments are contrary to the evidence
contained in the record. By reviewing
the economic development projects completed by OTP in 2006, it is clear that
those efforts are directed to businesses in small towns within OTP’s service
territory, not to any Otter Tail Corporation non-utility subsidiary.[465] Only one non-utility subsidiary is located in
OTP’s service territory (Shoremaster in
347. AG Processing argued that other agencies are involved
in economic development and, therefore, OTP does not need to have an economic
development program.[467] The fact that others are involved in economic
development efforts does not change the legitimacy of OTP’s request for rate
recovery in this case. In all instances
where the Commission has addressed economic development cost recovery, other state
and regional agencies have been involved in economic development efforts along
with the utility. OTP’s program was designed
to leverage other available economic development efforts. That is the fundamental nature of the loan
pool concept and the community matching-grant concept, in which each requires
participation by other economic development interests.[468] The labor component of OTP’s program is
largely spent coordinating economic development funds available from other
agencies, as demonstrated by the 2006 projects discussed by Ms. Brutlag.[469] Representatives of other economic development
agencies provided supportive public comments at the public hearings in this
case, noting that OTP has been instrumental in coordinating successful economic
development projects in the small rural towns served by OTP.
349. OTP proposed a three-year amortization of rate case
expenses, at a rate of $486,822 per year (after accepting the Department’s
correction of an allocation factor).[470] OTP also proposed that a deferral account be established
for any rate case expenses that are collected for any period of more than three
years. These amounts would be subject to
a credit toward expenses in OTP’s next rate case. OTP noted that this approach was taken in the
Commission’s decision in the 2006 Xcel
Energy Gas Rate Case.[471]
350. The Department and the OAG recommended amortization
over five years. The Department asserts
that the historical average of years between the Company’s rate cases is 6.4
years.[472] The OAG relies on the fact that is has been
over 20 years since the Company’s last rate case.[473] Both the Department and the OAG rely on prior
history that is not representative of the future, specifically the economic
conditions that prevailed in the electric utility industry and for the Company
between 1987 and 2007. OTP noted that the average duration between its rate
cases before 1987 was 2.75 years.[474]
351. OTP noted that it has begun a substantial capital
investment program, which is estimated to involve approximately $759 million of
investment over the next 5 years, including approximately $336 million relating
to Big Stone II and $423 million relating to other projects.[475] OTP maintained that going forward with either
category of investment will require frequent rate case filings.
352. The Commission noted the significance of utility
plans and utility investment cycles in approving a three year amortization in
the 2006 Xcel Energy Gas Rate Case. [476] With OTP’s investment plans, OTP’s plans
regarding rate case filings, and the dissimilarities between the current period
and conditions since 1987, the three year amortization period is
reasonable. Establishing a deferral
account for rate case expenses recovered beyond the three year period is a
sound approach to avoid over-recovery from ratepayers.
XVI.
charitable
contributions and organizational dues.
353. OTP has proposed including in its revenue requirement
$92,377 for Charitable Contributions, which reflects 50 per cent of OTP’s
charitable contributions.[477] OTP provided in its case filing the
information required by the Commission’s Statement of Policy on Charitable
Contributions.[478] The Department agreed with the amount of
Charitable Contributions that OTP Tail has proposed for recovery.[479]
354. OTP also proposed inclusion in its revenue
requirement $211,315 of organizational dues.[480] The Department recommended a $9,061
adjustment which would reduce the amount included in OTP’s revenue requirement
for organizational dues to $202,254.[481] The Department’s recommended adjustment to
organizational dues is in part based on a concern regarding out-of-state
Chamber of Commerce dues. The Department
also noted that some of the amounts paid may be going to organizations not
located in
355. AG Processing argued that a portion of Otter Tail’s
charitable contributions and organizational dues should be allocated to its
non-regulated businesses and only the remainder should be included in the
revenue requirement. [482]
356. OTP pointed out that, unlike charitable contributions
that are directly assigned to
357. OTP accounted for out-of-state Chamber of Commerce
dues below-the-line, and they were not part of the amount OTP included in its
revenue requirements. Only the
contributions and dues attributable to OTP’s regulated utility business have
been included in its request, and no amount has been included that would be
attributable to contributions or dues associated with OTP’s non-utility
businesses.[484]
358. Because OTP included only OTP’s charitable
contributions and organizational dues in its revenue requirement, allocating a
portion of this amount to Otter Tail Corporation’s non-utility subsidiaries
would not be appropriate.[485] Direct assignment is generally favored as
opposed to “indirect allocations” under Otter Tail’s proposed Corporate
Allocation Manual and prior Commission decisions.[486] Furthermore, if Otter Tail were to take an
indirect allocation approach to these contributions and dues, it would require
that the total aggregate contributions and dues be allocated.[487] There is no evidence in the record that would
support such an approach or from which the outcome of such an approach could be
determined.
359. OTP has met its burden of proof to show that its
charitable contributions are recoverable pursuant to Minnesota Statute §
216B.16, subd. 9, and that its organizational dues have been included in
revenue requirements consistent with the Commission’s Order in OTP’s last rate
case and with the Commission’s Statement of Policy on Organizational Dues.[488] No adjustment should be made to the amount of
charitable contributions and organizational dues included in OTP’s proposed
revenue requirement.
XVII.
Demand Side
Management (“DSM”) Rebate Programs.
360. In OTP’s 1986 rate case, the Commission denied
recovery for three DSM rebate programs -- thermal storage, water heaters, and
dual fuel. OTP is requesting recovery of
the expenses for similar rebate programs in this proceeding. At issue is $131,051 in expenses related to
those three rebate programs.[489] Mr. Lindell and Mr. Glahn opposed cost
recovery. Mr. Davis, on behalf of the
Department, supports cost recovery subject to OTP making certain modifications
to its water heating rebate. OTP agreed
to the requested changes with some modification, and Mr. Davis accepted those
modifications.[490]
362. Mr. Glahn recites the concerns the Commission raised
in 1986: (1) that those prior programs
increased usage more than they reduced demand; and (2) that customers would buy
the appropriate equipment without a rebate, making the rebates unnecessary.[491] Such participants are sometimes called “free
riders.” Mr. Glahn presented no evidence
to support a finding that these are still valid concerns. Mr. Lindell asked that a cost benefit
analysis be conducted.[492]
365. Mr. Davis’ only expressed concern with the program
was how OTP’s water heating rebate program was offered. OTP responded by changing the program to
address those concerns.[493]
XVIII.
Inventory of
Supplies And Materials.
367. The OAG observed that the amount of inventory of
supplies and materials included in rate base increased by 19 percent from
January 1 to December 31, 2006 (the test year period). The OAG asserted that the amount of increase
was unreasonable and proposed that the increase be limited to 10 percent. That adjustment would reduce OTP’s rate base
by $363,000.[494]
368. OTP noted that the principal reason for the increase
in inventories during the test year was that a large portion of OTP’s service
territory experienced a severe ice storm in late November and early December
2005. As a result, inventories of
transmission and distribution poles, conductors, transformers, and related
equipment were depleted. These
inventories were replenished during 2006, causing a significant increase in
inventory balances. Thus, the change in
the beginning and ending balances (19 percent) appears large, while the average
inventory was actually below normal.[495] Rate base is determined using a 13-month
average.[496] Because the rate base is an average of the
beginning and ending balances, if the initial inventory is lower than normal,
then, all else being equal, the average rate base used to set rates will also
be below the normal inventory level.
369. The increase in inventory was also, in part, the
result of an increase in the cost of equipment, such as conductors and
transformers, in recent years. For
example, the cost of some cable rose 88 percent from 2005 to 2007 due to rising
copper costs. During this same time
period, some transformers saw cost increases of 58 percent, also due to rising
raw material costs, such as oil, steel, and copper.[497]
370. OTP experienced inventory shortage problems due to
the 2005 ice storms. To address reliability
concerns, OTP increased its inventory of some equipment over previous levels. The average balance of supplies and materials
used in rate base for the 2006 test year is $5,772,171. By contrast, the average balance of supplies
and materials for actual year 2007 was $6,691,532. The significantly higher 2007 inventory
balance supports a finding that the 2006 test year amount is conservative.[498]
371. The OAG asserted that OTP’s lower inventory was the
result of mismanagement and, therefore, the amount of the increase should be
limited to 10 percent.[499] OTP adequately explained the depletion of inventories
as resulting from a severe ice storm and not mismanagement. OTP’s proposed average inventory in rate base
was reasonable. The supplies and
materials inventory included in OTP’s 2006 test year is representative of
future inventory levels. No adjustment
is needed.
XIX.
The Level Of
Fuel Stocks Included In Rate Base.
373. OTP noted that during 2005 and early 2006, two of
OTP’s generating plants, Big Stone I in northeastern South Dakota and Hoot Lake
near Fergus Falls, Minnesota, experienced problems with the rail delivery of
Wyoming coal. According to OTP, Big
Stone I’s coal stockpile would typically contain 30 days of coal. At the end of 2005, the stockpile was at 25
days. In March of 2006, that stockpile
was reduced, at its lowest point, to 15 days.
OTP described the shortage as so severe that the production at Big Stone
I was reduced for seven weeks to allow the coal supply to build up. At
374. As with the inventories for supplies and materials,
the rate base amount for fuel stocks was determined using a 13-month average.[501] OTP noted that, if the initial level of fuel
stocks is lower than normal, then, all else being equal, the average rate base
will also be below the normal fuel stock level.
375. OTP noted that during much of 2007, the days of coal
supply maintained in the stockpiles at both the Big Stone I Plant and the Hoot
Lake Plant were slightly higher than prior historical levels. OTP defended this decision as needed to
provide a cushion in the event that delivery problems recurred. OTP expressed its intention to maintain these
higher inventories as a hedge against possible future delivery delays. While the days of coal supply fluctuated
during the year, the average days of supply for Big Stone I in 2006 was
29. In 2007, Big Stone I averaged 40
days of supply. The average days of
supply maintained for
376. OTP noted that coal costs increased in 2007 over 2006
costs. During 2007, the average cost of
coal to the Big Stone I Plant increased by 6 percent, and the cost of coal to
377. The average fuel stocks value in the 2006 test year
(the same as actual 2006) for
378. The OAG suggested that the lower initial fuel stocks
were the result of mismanagement and, therefore, the amount of the increase
should be limited to 10 percent.[502] OTP adequately explained the depletion of
fuel stocks as resulting from rail delivery problems. These problems arose from independent parties
and they do not adversely reflect on OTP’s management practices. Having experienced fuel interruptions, a
reasonable response is to increase the fuel on hand.
379. OTP’s identified levels of fuel stocks included in
the 2006 test year were reasonable.
382. OTP noted that , in addition to the five major KPIs,
each OTP Department has its own KPIs.
Fuel costs are a separate KPI within the Generation Department. OTP’s management has determined that within
the hierarchy of its KPI system, the KPI for Generating Plant Availability is
the more appropriate primary indicator of performance in economic energy supply
because it is specific and because of the significant impact that outstanding
performance in Generating Plant Availability can have on the narrower goal of
fuel and purchased power costs.[503]
383. OTP described availability as representing the
portion of time that a generating unit is available to operate, including
consideration of the lost capacity effects of partial equipment deratings when
a unit is available but at less than full capacity. OTP has invested in very low-cost generating
plants that typically produce energy well below market prices. This makes performing well on the
availability measure very important. OTP
can reduce its overall energy costs by making sure it gets every possible megawatt
hour out of those very low-cost generating plants. Availability has more impact on OTP’s fuel
and purchased power costs than does any other factor over which OTP has any
reasonable control.[504]
B.
Different FCA
Mechanisms Used in OTP Service Areas.
385. OTP is required to use a different FCA mechanism to
recover changes in fuel costs in each of the three states in which it
operates. Mr. Schedin expressed concern
that OTP could be over-recovering its fuel costs as a result. OTP noted that no evidence was offered that over-recovery
has ever occurred.[505]
C.
Tariff
Modifications to Incorporate USOA Requirements.
387. The MCC proposed changing OTP’s tariff to restate the
accounting requirements established in the FERC Uniform System of Accounts
(USOA) with respect to fuel handling costs. OTP objected to the proposal as unnecessary
and unreasonable. OTP noted that this
change would require utilities to replicate the FERC system of account
requirements in their tariffs. [506]
389. The Department expressed concern that OTP’s bidding
of resources into the MISO Day 2 market did not include all costs imposed to
operate and maintain generators producing energy into the market (called
“O&M”). The Department asserted that
the effects of this practice must be taken into account in setting rates. Where a generation unit is dispatched by MISO,
the Department maintained that O&M costs should be included in the MISO Day
2 charges to be paid by the purchaser of the energy produced by the unit. The Department noted that all of these costs
would be included in the monthly FCA of each utility purchasing the energy from
the unit.[507]
390. The Department contended that if a utility fails to
adjust out of base rates the MISO-bid-related O&M expenses (non-fuel
expenses), there will be a double recovery of such expenses.[508] OTP maintained that it is not recovering the
O&M expense in generation bids in the MISO Day 2 Market. The Department maintained that OTP did not
provide sufficient support for its assertion that it is not recovering the
O&M expense of third parties included in generation bids from the MISO Day
2 market. The Department noted that the
MISO market allows the inclusion of such O&M expenses in the price quoted
for energy entered for sale into the market.
The Department characterized OTP’s choice to not recover the O&M
expense from the MISO market as a decision to have ratepayers pay those costs. The Department contended that OTP’s
shareholders, rather than ratepayers, should shoulder the burden of these
costs.[509]
391. The Department expressed its position as follows:
While
it is appropriate to pay the third-party generator what it costs for them to
produce energy from the plant, it is not reasonable for OTP’s ratepayers to pay
for both the third-party generator O&M costs via the FCA and OTP’s
generation O&M costs in rate base.[510]
392. OTP contended that there is no double recovery arising
out of the MISO Day 2 market because:
1.
OTP recovers its O&M expenses in its base rates.
2.
OTP uses an O&M cost component when developing its price for bidding
generation into the market.[511]
3.
OTP removes the cost of the O&M when it books the transaction to the
FCA (preventing a double recovery of the O&M costs -- it is recovered only
in base rates and not through the FCA).[512]
4.
Any third-party revenues in excess of costs are wholesale margins and
are credited back to the base rate revenue requirement.
5.
OTP is required to pay the market price established by third-party
providers when it buys energy, and that market price may include the
third-party providers’ O&M costs.[513]
6.
OTP’s ratepayers will only pay for the O&M costs of a third-party
provider for energy that OTP has not produced.[514]
396. OTP has met its burden to show that its O&M
expense is reasonable and that it is not double recovering these expenses.
A.
Agreed-upon Adjustments
to Rate Base.
397.
In setting rates
for a public utility, the Commission must determine the total level of
investment by the utility in its “utility property used and useful in rendering
service to the public.”[515] In utility
rate cases, such investments are referred to as the utility’s rate base. OTP filed a proposed rate base of
$207,779,343.[516] Through the
course of the proceeding, the Department and OTP agreed on the following
adjustments to the rate base as initially filed by the Company:
• Depreciation Reserve Related to 2007 Depreciation Rates.
Decrease test-year rate base by $636,397.[517]
• Depreciation Reserve Related to Big Stone I. OTP Errata recommended adjustment to decrease
test-year rate base by $58,816.[518]
• Big Stone I Acquisition Adjustment, removal from rate
recovery. Decrease test-year rate base by $245,833.[519]
• D1 Allocation Adjustment. All non-firm/curtailable loads are
excluded from OTP’s Generation Demand Allocator (D1) calculation. The overall
effect on rate base is a reduction in OTP’s production plant, accumulated
depreciation, and fuel stock balances for the
398.
The Department
noted that OTP included the cash working capital requirements for operation,
maintenance, and other expenses. OTP
applied lead/lag study factors to its test-year O&M expenses to determine
its cash working capital requirement. The
Department determined, after analysis, that these lead/lag factors were
reasonable. The Department and OTP agreed
that the lead/lag study cash working capital calculations will need to be
adjusted to reflect all of the changes to revenue requirements as finally
determined by the Commission.[522]
B.
Disputed Adjustment
to Rate Base.
399.
The Department
identified Transmission Demand Factor (D2) as the only outstanding rate base
issue. The Department and OTP agreed
that all non-firm/curtailable loads should be excluded from OTP’s Transmission
Demand Allocator (D2) calculation. The Department and OTP agreed to the revised
D2 allocator for
400.
However, the
Department and OTP did not agree on other aspects of the D2 allocator, with
respect to OTP’s assertion that the Company’s 41.6kV and 69kV lines are
transmission facilities and that the costs associated with them should be
allocated on the same basis as OTP’s 115kV and 230kV lines.[524] OTP has shown
that its 41.6 kV facilities are largely located in North and
While load
factor is one relevant element relating to the size (capacity) of the
transmission facilities needed to serve a customer with a high load factor,
using load factor alone ignores relevant geographical considerations such as
the miles of transmission lines in a given state needed to serve customers
located throughout the state. The [Department’s]
concern is with allocating transmission costs on a more cost-causative basis
which creates a reasonable and fair allocation for
401.
The Department
urged a “common sense” standard that more of OTP’s lower-voltage 41.6kV
transmission facilities costs be allocated to North and
A.
Class Revenue
Apportionment.
The Commission requires utilities to file a CCOSS because the cost a
utility incurs to provide service is one factor the Commission considers in
determining how much each customer class should contribute to meeting the
utility’s revenue requirement, and how to recover each class’ share of the
revenue requirement from the members of the class. Other factors include economic efficiency;
continuity with prior rates; ease of understanding; ease of administration;
promotion of conservation, ability to pay; and ability to bear, deflect or
otherwise compensate for additional costs.[530]
403. OTP apportioned its total revenue responsibilities
among its rate classes based on its CCOSS and its rate design objectives,
including the objective of maintaining reasonable rate continuity, mitigating
rate shock, and encouraging the efficient use of resources.[531] OTP proposed the following allocation and
noted the impact of asset-based margin credits through the FCA as follows:
|
Class
Revenue Responsibility — Proposed increase by class[532] |
|||||
|
|
|
|
Proposed Increase by Class
Responsibility |
||
|
Customer Class |
|
|
Amount of Increase (as originally proposed) |
Percent Increase |
Percent Increase With FCA Adjustment |
|
Residential |
|
|
$4,522,094 |
12.50% |
9.10% |
|
Farms |
|
|
286,159 |
13.25% |
9.20% |
|
General Service |
|
|
1,538,033 |
5.88% |
2.50% |
|
Large General Service |
|
|
6,081,942 |
10.50% |
5.25% |
|
Irrigation |
|
|
40,461 |
14.00% |
9.51% |
|
Lighting |
|
|
273,006 |
11.50% |
9.16% |
|
OPA |
|
|
167,790 |
14.00% |
9.15% |
|
ControlIed Service Water Heating |
|
|
215,284 |
15.00% |
10.05% |
|
ControlIed Service Interruptible |
|
|
1,298,236 |
40.00% |
31.80% |
|
ControlIed Service Deferred |
|
|
86,516 |
12.00% |
6.03% |
404. The OAG recommends a flat, across-all-classes rate
increase, without any regard for OTP’s embedded CCOSS.[533] Such an approach would subsidize residential
customers by having costs incurred by that class paid for by other customer
classes.
405. MCC recommends a strict adherence to the CCOSS,
without any regard for non-cost factors.[534] Such an approach would shift costs away from members
of the LGS class.
The largest percentage increases come for the customer classes receiving
the largest percentage subsidies and thus having the largest relative
differences between present revenues and full-cost recovery revenues. For
example, Controlled Service Water Heating has a gap between current revenues and
full-cost recovery revenues of $868,570; Otter Tail’s proposed revenue
apportionment covers $215,284, or about one-fourth of the gap. Under my
proposed revenue apportionment, $437,354, or slightly more than half of the gap
is closed. The same is true for Irrigation, where the corresponding amounts are
$149,741, $40,641 (one-fourth of the gap), and $77,608 (slightly more than half
of the gap). For the Residential class, the difference between current revenues
and full-cost recovery revenues is $6,334,726, Otter Tail proposes to cover
$4,522,094 (about 71 percent of the difference), while my proposal is to cover
$5,138,259 (81.1 percent of the difference).[535]
407. The Department’s proposed revenue allocation between
classes is as follows:
|
Department
— Proposed Increase by Class[536] |
|||||
|
|
|
|
Proposed Increase by Class
Responsibility |
||
|
Customer Class |
|
|
Proposed Revenue Increase |
Percent Increase |
Total Revenues as Percent Increase Total Required Revenues |
|
Residential |
|
|
$5,138,259 |
14.20% |
97.19% |
|
Farms |
|
|
352,442 |
16.32% |
95.13% |
|
General Service |
|
|
462,356 |
1.77% |
105.00% |
|
Large General Service |
|
|
6,081,942 |
10.50% |
101.30% |
|
Irrigation |
|
|
77,608 |
26.85% |
83.56% |
|
Lighting |
|
|
371,147 |
15.63% |
99.51% |
|
OPA |
|
|
198,048 |
16.52% |
95.96% |
|
ControlIed Service Water Heating |
|
|
437,354 |
30.47% |
81.28% |
|
ControlIed Service Interruptible |
|
|
1,310,914 |
40.39% |
99.46% |
|
ControlIed Service Deferred |
|
|
79,415 |
11.02% |
101.58% |
|
|
|
|
|
|
|
408. OTP noted that many individual OTP customers take
service under two or more rates resulting in a cumulative rate impact (e.g., residential service, and one or
more demand controlled rates).[537] For example, OTP’s proposed Controlled
Service Water Heating Rate, by its nature, will not likely be the sole rate
under which a customer takes service.
Instead, such a customer will also take service under another, less
use-specific rate, such as the Residential Service Rate. That customer will experience both the
residential increase and the Controlled Service rate increase. OTP maintains that the cumulative rate impact
of these two rates increases should be considered in the revenue apportionment.
OTP argues that the Department’s
proposal did not take into consideration the cumulative rate impact that a
single customer could experience if taking service under two or more rates.[538]
Once
revenue requirements have been determined, it remains to decide how, and from
whom, the additional revenue is to be obtained.
It is at this point that many countervailing considerations come into
play. The commission may then balance
factors such as cost of service, ability to pay, tax consequences, and ability
to pass on increases in order to achieve a fair and reasonable allocation of
the increase among the consumer classes.[539]
410. The Commission has identified a number of cost and
non-cost factors to consider when determining customer class revenue
responsibility. Both types of factors are
important to determine just and reasonable rates. These factors identified by the Commission include
avoidance of rate shock for individual customer classes, low-income customers’
ability to pay, a company’s ability to recover the rate increase from others,
the ability of companies to decrease the burden of a rate increase through tax
deductions, and the recognition of the historical continuity of rates and rate
increases.[540]
B.
Use of Marginal
Costs in Rate Design.
412. OTP developed its rate design from the revenue
requirements identified in its marginal cost of service study.[541]
414. There are three primary reasons for using marginal
costs in rate design. First, rates set
at marginal cost provide the most efficient price signals to consumers, and
promote the wise use of resources.[542] Second, the use of marginal cost pricing
reduces cross subsidies.[543] Cross subsidies can arise when costs
attributable to consumption by one customer or group of customers are recovered
from another customer or group of customers.[544] Third, when rate structures are based on
marginal cost, the utility’s revenues are more likely to track its total costs
as electricity consumption changes.[545]
415. OTP’s proposed rate design was based on marginal
costs, as adjusted to match the proposed revenue requirement in a manner that
retained the benefit of marginal cost price signals.[546]
416. MCC witness Schedin and Enbridge witness Erickson
argue that the generation portion of OTP’s marginal cost study is too
short-term focused and that it should have reflected the future costs of Big
Stone II, OTP’s next planned baseload addition.[547] However, a marginal cost study from which
rates will be designed should reflect the marginal costs that will be incurred
during the period the proposed rates are expected to be in effect.[548] Otter Tail’s marginal cost study does that.[549] This approach results in price signals that
are as close as possible to the expected costs to supply additional kW and kWh
while the rates are in effect.[550] For example, if OTP needs additional (or
less) capacity during the period the rates are in effect, it will buy (sell)
capacity. OTP’s marginal cost study was
properly based on the market cost of such capacity.[551] Even when OTP builds additional generating
capacity, its marginal capacity cost will still be a function of market prices.[552] It is appropriate to use market prices
because they reflect the actual effect on OTP and its customers as a whole, of
a change in energy use in a given hour.[553] OTP’s approach is consistent with common
industry practice to base marginal costs on market price forecasts.[554]
417. OTP maintained that reflecting the capacity costs of
future baseload additions, such as Big Stone II, in current demand charges would
be inappropriate. MCC and Enbridge argue
that such costs should be reflected in current demand charges. OTP argues that this approach would effectively
base one rate component (demand charges) on the costs of future capacity
additions, and another component (energy charges) on current marginal
costs. OTP maintains that this would result
in a distortion in the signal regarding the relative costs of energy and
capacity.[555]
419. MCC asserted that OTP provided no cost study
justification for its voltage level discounts.
OTP provided marginal energy and capacity costs by voltage level,
showing the differences in marginal cost for primary and transmission service,
compared to secondary service and the differences in charges.[556] MCC’s position is unfounded.
420. OTP provided an embedded CCOSS that used the same
classification methods as were used in the CCOSS approved in OTP’s 1986 rate
case.[557] The only parties to comment on the CCOSS were
the Department and MCC. OTP accepted the
two modifications to the CCOSS requested by the Department. MCC proposed that a breakeven methodology be
used to determine the portion of production plant costs to treat as demand
versus energy costs.[558] This proposal was opposed by both OTP and the
Department.
421. The Department recommended acceptance of OTP’s CCOSS,
as adjusted to reflect OTP’s agreed upon adjustment to the D-1 factor and to
allocate conservation expenses in a manner consistent with Mr. Davis’ proposal.[559] OTP accepted the Department’s requested
modifications.
422. OTP used an equivalent peaker methodology to
determine the portion of production plant costs to treat as demand versus
energy costs. While the MCC initially
proposed using its breakeven methodology for both CCOSS and JCOSS purposes, at
the evidentiary hearing, Mr. Schedin stated that “in the interest of not
impacting the total revenue requirement due from the
423. The breakeven methodology reallocates production
plant costs from energy to demand. That,
in turn, benefits customer classes that use more energy per unit of demand
(high load factor customers).[561] Mr. Schedin testified that using the
breakeven methodology in the CCOSS, as compared to the equivalent peaker
methodology, would shift $942,000 in cost responsibility away from the high
load factor customers in the Large General Service (“LGS”) class to lower load
factor classes and customers (primarily to the Residential Class because of its
comparatively lower load factor).[562]
The
determination of Base and Peak Demand amounts is based on the premise that all
plants are or can be used to supply peak demand. However, base load plants (steam and hydro)
are used to supply the bulk of the energy used on the system. Therefore, the base load plants have a dual function
of supplying both peak energy and demand.
The … classification of production plant into base and peak categories
recognizes this fact and assigns a portion of the base load plants to each of
these functions. The underlying
assumption is that the cost to supply a peak kW of demand capacity to the
system is the cost of a peaking plant.[563]
425. The equivalent peaker methodology (also called a
stratification methodology) was approved for use in OTP’s 1986 rate case and in
Xcel Energy’s previous seven rate cases.[564] In the 2005 Xcel Energy Rate Case, the
Commission explained why the stratification methodology is reasonable, stating
as follows:
Electric
utilities incur both fixed and variable costs.
The cost of building a generator is generally fixed; they do not change
in proportion to the amount of energy generated. In contrast, many operating costs are
variable; they change depending on how much the plant is operated. Because a utility must build its plant
sufficient to supply the electricity required by customers even on days of peak
demand, fixed plant costs are typically regarded as demand-related costs. In contrast, energy-related costs—such as the
cost of fuel or electricity purchased from other generators—are typically
variable.
But not all energy-related costs are
variable. For example, a utility may buy
a generator that is expensive to build but uses inexpensive fuel (typical of a
“baseload” generator) over a generator that is inexpensive to build but requires
expensive fuel (typical of a “peaking” generator). In this case, the choice to incur extra fixed
building costs may be understood as a substitute for incurring extra fuel
costs.[565]
426. The record in this proceeding is consistent with the Commission’s
rationale in the 2005 Xcel Energy Rate Case. It is the need for both capacity and low-cost
energy in excess of that provided by a peaking facility that justifies
incurring the higher capital costs associated with a baseload plant. In explaining the relationship between the
investment and energy costs, Dr. Parmesano stated :
As the NARUC Manual that Mr. Schedin
quotes makes clear [see, for example, NARUC Manual, p. 49, 53-54],
utilities invest in generation capacity with fixed costs higher than the fixed
costs of a peaker only if they expect to run the unit for enough hours of the
year to offset the higher fixed costs with fuel savings. Therefore, a
significant share of the fixed cost of a baseload plant is incurred to provide
inexpensive energy.[566]
427. MCC notes that Mr. Schedin and Dr. Parmesano agree that,
from a resource planning perspective, a baseload plant will be built once the
operating hours exceed those appropriate for a peaking plant. MCC maintains that this agreement implies
support for the breakeven analysis.[567] Dr. Parmesano did not indicate that there any
correlation between the resource planning decision and the determination of
what is demand related cost in a cost of service study. Dr. Parmesano characterized the foundation of
OTP’s approach as follows:
Beyond
the cross-over point, a baseload unit continues to provide energy savings that
offset some of its fixed costs. This
fact is the foundation of the equivalent peaker approach used by OTP and Xcel
Energy and many other utilities. It is
also the foundation of all the many “Energy Weighting Methods” described in the
NARUC manual.[568]
The demand deficiency forecasts in OTP’s
revised certificate of need application for Big Stone Unit No. 2 and the lack
of energy deficiency forecasts clearly demonstrates that this new large
baseload unit is being proposed on the basis of meeting OTP’s peak demand not
energy, i.e., the need is demand driven rather than energy.[569]
429. Department witness Dr. Ouanes disagreed with Mr.
Schedin’s argument on two grounds.
First, Dr. Ouanes maintained that “there is no reason why a utility
would incur the higher capacity cost of baseload generation if not for the
lower cost energy baseload plants provide.”[570] Second, the need for Big Stone II is based on
energy and capacity, described in the Big
Stone II proceeding as follows:
The issue of what need is the driving force
behind the proposal for the Big Stone II facility appeared during the cross
examination of multiple witnesses. This
issue was originally discussed in my November 17, 2006 direct testimony at
pages 10 to 17. The facts of the matter
are the claimed need is for energy and capacity, that all utilities have an
energy need, and not all utilities have a capacity need. Thus, energy is the issue linking all of the
Applicants. Further if only capacity
were needed, a baseload plant would not be proposed. If only energy were needed, a baseload plant
could still be proposed. Thus, energy is
the more important factor.[571]
At the evidentiary
hearing, Mr. Schedin acknowledged that the plant is actually proposed for both
capacity and energy needs.[572]
430. Under the methodology used by OTP, 61.1 percent of
the production plant is treated as energy related, while, under the breakeven
analysis, Mr. Schedin treated only 16 percent as energy related.[573] Dr. Parmesano described this result as very
extreme, stating:
I am not aware of any commonly used
embedded cost of-service method, other than treating all fixed costs as
demand-related, that would define such a large share of production fixed costs
as demand-related. And treatment of all
fixed costs as demand-related is totally inconsistent with the factors that
lead a utility to invest in baseload plant.[574]
431. Mr. Schedin claimed that his methodology was
supported by the NARUC manual’s description of the production stacking
method. However, upon examination, the
NARUC manual’s example of the production stacking method resulted in 89.72
percent of the production plant being classified as energy related and only
10.28 percent as demand related.[575] That is the reverse of the results Mr.
Schedin obtained under the breakeven methodology.
432. MCC asserts that the approved methodology
approved in the 1994
436. In response to the Department’s recommendation, OTP agreed
to continue phasing out declining block rates by supporting the elimination of
the declining block features from two of the remaining four rates: the General
Service 20 kW and Greater and Large General Service (LGS) rates. OTP’s revised proposal retains declining
block rates for only the following rates:
Residential and General Service under 20 kW.[580] For these two rates, the declining block rate
features have been substantially reduced, and OTP indicated that these
declining block rates will be proposed for elimination in OTP’s next general
rate case.
437. Eliminating all declining block rate structures would
satisfy several of OTP’s rate structure objectives, such as the objectives to
reflect marginal costs, promote efficient use of resources and
conservation. OTP contends that these
objectives should be balanced with the objectives of maintaining reasonable
rate continuity and avoiding large bill impacts associated with rate design
changes (“rate shock”).[581]
438. OTP’s approach is less abrupt than the Department’s,
offering a more moderated approach that would smooth the transition to more
economically efficient rates and mitigate to some extent the rate impacts
associated with this rate design change.[582]
439. MCC’s proposal that the LGS rate continue to include
a declining load factor block rate structure, is based on its view that the
rate is “reflective of two or three shift manufacturing operations” which use
energy during off-peak, nighttime hours when the cost of energy is low.[583] OTP responded that this argument confuses
declining block rate structures with time-of-use (or load factor) rate
structures. OTP maintained that the load
factor block structure is an inadequate substitute for time-of-use pricing and
can result in inefficient price signals.[584] OTP offered evidence that its customers do
not exhibit a systematic decrease in their peak share of energy use or
systematic increase in their off-peak and shoulder shares of energy use as the
monthly load factor increases.
Therefore, load factor blocks are not necessary to reflect higher
off-peak use by higher load-factor customers.[585]
440. OTP noted that customers with relatively high
off-peak and shoulder-period consumption with the ability to change their load
patterns to use a larger percentage in off-peak and shoulder periods also have
the ability to switch to the LGS-TOD rate, which appropriately charges
customers based on their actual peak, shoulder and off-peak loads.[586]
E.
Residential
Customer Charge.
442. Customer billings are typically comprised of a
monthly customer charge, paid by any customer connected to a utility’s system,
and usage charges for the electricity consumed.
The monthly customer charges are set by class and may differ by zones
within a utility’s service area. OTP’s
existing urban Residential Customer Charge is $6.15 and the rural rate is
$7.15. OTP proposed increasing the
Residential Customer Charge to $8.00 for both urban and rural customers. The Department supports an $8.00 customer
charge, with an increase to $8.50 in two years.[587] The OAG recommends retaining the $6.15 rate
and lowering the rural rate to $6.15.[588]
443. As noted by the Department, OTP’s marginal cost of
providing residential customer service is $11.83.[589] Because the customer charge is below the
customer cost, it is necessary to recover the unrecovered customer costs
through the energy charge. As a result,
customers with more than average usage pay more than their proportionate share
of these costs.[590] OTP maintains that this constitutes an intra-class
subsidy that is inconsistent in application.
Minn. Minn. Stat. § § 216B.03, provides in part:
Rates
shall not be unreasonably preferential, unreasonably prejudicial, or
discriminatory, but shall be sufficient, equitable, and consistent in
application to a class of customers.
445. Mr. Lindell objected to the proposed increase in the
Residential Customer Charge. He
maintained that the increase amounts to 28% over the existing charge and that
such an amount would cause rate shock. OTP
responded that an increase of less than $2 after 20 years of no change in the
customer charge does not qualify as rate shock.[591] OTP noted that the customer charge is only
one component of the overall bill. OTP
maintained that heavier usage customers are the most affected by a rate case
increase.[592] Those customers are least affected by a
change in the Residential Customer Charge.
447. The OAG maintained that any increase in the customer
charge contravenes the directive in Minn. Minn. Stat. § § 216B.03 to
promote conservation.[593] OTP contended that this statutory provision, in
effect since 1974, has never been interpreted as precluding reasonable
increases in the customer charge. OTP contends that recovering less than $2.00 per customer
per month through the monthly customer charge is unlikely to have a significant
impact on customer’s incentive to conserve energy. OTP considered a conservation response to be
far more likely to result in response to the overall bill increase resulting
from this proceeding.
448. The OAG relies on the Commission’s decision in the 2004 CenterPoint Energy Rate Case, which
rejected an $8.00 customer charge, in part, based on the desire to promote
conservation.[594] OTP maintained that the Commission’s decision
was influenced by CenterPoint Energy’s proposal of a 60 percent increase in the
customer charge. The Commission instead
approved a $1.50 (30 percent) increase to $6.50. OTP noted that the Commission approved an
increase in the customer charge for Xcel Energy to $8.00, which constituted an
increase of $1.50 from $6.50. In setting out its reasoning for the Xcel
award, the Commission stated in part:
The
customer charge has two main functions, one practical and one grounded in
ratemaking policy. Its practical
function is to help stabilize utility revenues and reduce the risk that the
utility will over- or under- recover its revenue requirement due to
weather-related fluctuations in gas usage and sales. Its ratemaking function is to ensure that
each customer bears responsibility for a certain level of the Company’s fixed
costs regardless of usage.[595]
After acknowledging that Residential customer charges
cause customer dissatisfaction, the Commission went on to state:
[C]ustomer
charges play an important role in the rate structure. They reduce utilities’ capital costs by ensuring
baseline levels of revenue, thereby reducing consumers’ rates. They help mitigate rate volatility between
seasons by recovering some fixed costs during the low-usage, summer months. They promote equity by ensuring that the rate
structure does not shift the full system-costs imposed by low-usage and
seasonal customers to normal-usage, high-usage, and year-round customers.[596]
449. While OTP did not oppose increasing the rate to $8.50
in this proceeding, OTP objects to the Department’s proposal to increase that
rate outside of a rate case in two years.
An increase to $8.50 would move the Residential Customer Charge closer
to marginal costs and is consistent with OTP’s rate design objectives. However, if the increase does not occur as
part of the current proceeding, OTP would prefer to wait until its next rate
case, which it anticipates filing within three years, when it would have an
updated marginal cost study to assist in determining the appropriate rate.[597]
454. OTP’s proposed rate includes a facilities charge that
varies by size of secondary customer (in terms of maximum annual kW) and varies
by voltage level. These charges are
approximately half of marginal cost.
There is no customer charge, but the minimum bill is set at the sum of
$350 (approximately marginal customer cost) and the facilities charges.[598]
1.
Use of Marginal
Costs in LGS Design.
456. OTP’s Proposed LGS rate design is based upon marginal
energy and capacity costs.
457. The MCC criticisms of OTP’s use of marginal costs in
the design of the LGS rate are largely based on a number of errors in their
understanding of the rate.[599] Their largest objection relates to the
mistaken belief that OTP included capacity costs as part of energy costs in the
rate and greatly understated the value of capacity costs.[600] Those criticisms confuse marginal cost-based
rate design principals and embedded cost-based rate design principals.[601]
458. Shifting from an embedded cost rate structure to a
marginal cost rate structure necessarily implies changing the relationships
between energy and demand charges in order to provide customers with more
efficient price signals.[602] These features of the LGS rate (and all OTP
rates) are reflective of OTP’s objective to move to marginal cost-based
rates. Marginal cost-based rates satisfy
several rate design objectives including efficiency of price signals and
promotion of conservation.
2. Elimination of Declining Energy
Block from LGS Rate.
459. The MCC argues that the declining block should be
retained in the LGS rate in order to create an incentive for customers to
operate during non-peak periods.[603]
460. The declining energy block rate structure is not a
reasonable approximation of time-of-use pricing.[604] Furthermore, OTP’s LGS customers do not
exhibit a systematic decrease in their peak share of energy use or systematic
increase in their off-peak and shoulder shares of energy use as monthly load
factor increases. Therefore, MCC’s
assumption that load factor blocks are necessary to reflect higher off-peak use
by high load factor customers is incorrect,[605] and the
suggestion that the LGS rate should retain the declining energy block is not
recommended.
G.
OTP’s Proposed
LGS-TOD Rate Design.
461. OTP’s proposed LGS-TOD rate makes several
improvements to OTP’s existing rate: it
reflects a four-month summer/eight-month winter seasonal pattern of costs; it
includes three diurnal periods; and it reflects OTP’s marginal costs. [606] The seasonal change has not been challenged
by any party.
462. Based on its criticism of OTP’s marginal cost study,
Enbridge proposed that no change be made to OTP’s existing Time of Day Rider.[607] The foregoing discussion on the
appropriateness of OTP’s marginal cost methodology addresses this criticism.
465. The MCC recommendation bases one rate component
(demand charges) on the cost of future capacity additions, and another
component (energy charges) on current marginal costs. This approach is likely to result in an
inefficient signal to consume more energy in all hours except the hour in which
the customer set its billing demand.[608]
467. OTP noted that only three customers take service
under this rate. OTP considered customer
confusion implausible because these customers have experts managing their energy
use. These managers are in frequent
contact with OTP senior Industrial Services Engineers.[609]
468. Enbridge criticizes the change in periods not because
of complexity, but because they are different from other utilities from which
Enbridge Energy takes service and, therefore, they are concerned that this
difference may complicate load management across Enbridge’s multi-state
pipeline.[610] The comparison rates provided by Enbridge do
not reveal great differences among the OTP’s proposed periods and the periods of
the comparison utilities.[611]
469. Enbridge also recommended that holidays all be
treated as off-peak, but OTP’s analysis of holidays showed that high loads on
OTP’s system can occur on holidays, and, therefore, treating them as off-peak
would not be consistent with actual consumption patterns.[612]
H.
Standby Service
Rate Design.
471. OTP proposed a Standby Service rate which
fundamentally reflects its current Standby Service offering and is based upon
the rate design for the proposed LGS-TOD rate.[613] The proposed changes to the Standby Service
rate (like the LGS-TOD rate) reflect updated seasonal and costing periods and
are based upon OTP’s marginal costs.
472. The MCC maintained that the proposed additions to the
Standby rate are “very complicated” compared to OTP’s current rate.[614] OTP contends that the only changes proposed
are the addition of one diurnal energy charge (shoulder) and the addition of
seasonality to the demand charges (summer and winter).[615] OTP maintains that these proposed additions
improve the price signals inherent in the rate and reflect the similar changes
that have been made to the LGS-TOD rate.
473. OTP maintains that those customers likely to take
service under the Standby Service rate will have no difficulty understanding
these additional features.[616] The nature of the rate requires that customers
be sophisticated in energy matters as they will necessarily have on-site
generation. These customers will likely
be business owners with a fair level of business sophistication.[617]
474. MCC asserted that OTP’s current Standby Service rate
structure should be retained. OTP objected to this proposal. The pricing structure of the proposed Standby
Service mirrors many features contained in OTP’s proposed LGS-TOD rate. OTP argued that the relationship to the
proposed LGS-TOD rate is consistent with the relationship between the current
Standby Service Tariff and the current LGS-TOU rate.[618] OTP described the proposed changes as merely
reflecting updated seasonal and costing periods and are based on marginal
costs, which improve the overall efficiency of the rates.[619]
475. Additionally, MCC argued that Standby Service
customers should be allowed to choose their supplemental service rate rather
than being required to take supplemental service under the LGS-TOD rate. OTP contended that this would not be
appropriate due to the rate design. The
existing LGS-TOU rate and the Standby Service rate were created in coordination
with one another.[620] This practice of prescribing the LGS-TOU as
supplementary service under the Standby Service rate has been in effect since
1993.[621] No compelling reason has been offered to
support changing these rates.
I.
Ag-Processing
Rider Proposed By MCC.
477. MCC claims that OTP should be required to design and
offer a special AG Processing rider similar to that offered by Minnkota Power
Cooperative.[622] OTP contended that such a rate would be
redundant with rates it already offers. [623] OTP noted that its LGS rider has wide
flexibility. OTP and an Ag-Processing
customer (or a customer from any industry) could design a customer-specific
rate, which would include a load management component and other
customer-specific features.[624] Because OTP’s proposed LGS rider already
provides an adequate vehicle for customizing a load management rate and
provides better flexibility than adopting a rate design of another utility as
MCC proposes, a specific Ag-processing rate is not needed.[625]
478. If OTP were required to offer an Agri-Processing
Rider, it would need to be designed based on cost information specific to
OTP. The MCC’s proposed interruptible
rate for Ag-Processing loads has an inconsistency between the interruptible
rate charges and the limits on interruptions.[626] In recent years, OTP typically has controlled
customers on its interruptible riders in the range of 200 to 400 hours per
season.[627] The MCC AG Processing proposal would limit
interruptions to 100 total hours per season.[628] Unless customers on such a rate are
interruptible for as many hours as OTP has non-zero marginal generation,
transmission, and distribution substation/trunk feeder costs, it would not be
appropriate to eliminate all generation, transmission and distribution
substation/feeder capacity costs from the demand charges. [629] Such a rate design would result in a subsidy by
other customers.[630]
J.
Proposed
Revisions to OTP’s Tariff.
97. Section
1.02 APPLICATION FOR SERVICE shall be revised to
read as follows:
Anyone desiring electric service from the
Company must make application to the Company before commencing the use of the
Company’s service. The Company reserves
the right to require an Electric Service Agreement before the service will be
furnished. Receipt of electric service
shall constitute the receiver a Customer of the Company subject to its rates,
rules and regulations, whether service is based upon the Tariff, an Electric
Service Agreement, or otherwise. All
applications and contracts for service shall be made in the legal name of the
party desiring service. The Customer will be responsible for payment of all
services furnished.
A Customer may
take service pursuant to any Commission-approved rate(s) for which the Customer
qualifies. The Customer shall be
required to take service under the selected rate(s) for a minimum of one (1)
year, unless the Customer desires to change its service to any rate offering
that is newly approved within the one-year period and for which the Customer
qualifies. If a Customer changes its
service to a different rate, the Customer shall not be permitted to change back
to the originally applicable rate for a period of one (1) year. A Customer shall provide the Company at least
45 days prior notice in the event of any requested change.
Unless otherwise agreed to by the
Company because of Customer hardship, a Customer shall be required to obtain
service from the Company under the service Tariff that has been determined to
be applicable for that Customer at that service location, for a minimum period
of one (1) year. If a Customer changes
the provision of service to a different service Tariff that is applicable to
the Customer at that location, the Customer shall not be permitted to change
back to the originally applicable service Tariff for a period of one (1) year.
98. The First Paragraph of SECTION 3.02 Curtailment or
Interruption of Service shall be revised to read as follows:[631]
The
Company may curtail or interrupt service without notice to any or all of its
Customers when in the Company’s judgment such curtailment or interruption will
tend to prevent or alleviate a threat to the integrity of its electrical system
or whenever requested to do so by any regional Reliability authority. If, in the Company’s judgment, curtailment or
interruption of service to some but not all of the Company’s Customers is
warranted by the circumstances, the Company shall select the Customers to be
curtailed or interrupted. The Company
shall have no liability for any reason whatsoever resulting from any
curtailment or interruption made pursuant to this paragraph. Any curtailment or interruption of service to
the Customer will not relieve the Customer’s obligations to the Company. Upon
request from any Customer, Company shall make reasonable effort to provide
notice to such Customer of a projected curtailment or interruption in service,
in the event Company has advance notice of curtailment or interruption of such
Customer’s service. However, Company
shall have no liability to Customer or to any third party for Company’s failure
to give such notice, or for erroneously or mistakenly giving such notice.
99. SECTION 4.14 COMBINED METERING shall be added as follows:
Combined Metering is defined as the addition of
multiple service or metering points so that the energy and demand is registered
on one meter. This results in coincident
demand for these loads, thus treating it as one larger load for billing one
rate. To quality for Combined Metering a
Customer must be served at a premises consisting of contiguous property with
the same occupant and each service entrance to be combined must have a minimum
entrance rating of 750 kVA (750 kVa entrance at various voltages which is
equivalent to: 900 amps @ 277/480; 1800
amps @ 120/240 delta; 2100 amps @ 120/208 wye).
Combined Metering can be accomplished with hardware or software
totalizers or by installing primary metering. The Company will, in its sole
discretion, reasonably determine whether to use primary metering or totalizing
for any particular Customer that qualifies for Combined Metering.
100. Section 5.01 EXTENSION RULES AND Minimum
Revenue Guarantee shall be
revised to read as follows:
The Company will, at its own expense,
extend, enlarge, or change its Distribution or other facilities for supplying
electric service when the anticipated revenue from the sale of additional
service at the location justifies the expenditure. If it reasonably appears to the
Company that the expenditure may not be justified based on a three-year
projection of revenue received from the Customer’s applicable rate(s) (not
including any such amounts expected to be recovered through the fuel adjustment
rider, but including any base costs of energy included in the Customer’s
rate(s)), the Company may require the Customer to (a) sign an
Electric Service Agreement guaranteeing a minimum payment of no less than three
(3) years use of electric service, or (b) such other period of service as
may be justified by the Company, or to require the Customer to make payment
in advance in the event the Company determines on a commercially reasonable
basis that the Customer may not maintain adequate creditworthiness over the
period or may fail to make payments for service over the period.
The Company shall provide to the Customer an estimate
with detail of the costs prior to construction.
If at the point of true-up at the end of the agreed
to initial period of service, the Customer uses and pays for more than the
specified amount of electric service, (not including any such amounts paid
pursuant to the fuel clause adjustment rider, but including any amounts paid
for the base costs of energy included in the Customer’s rate(s)), excluding
that portion representing fuel cost recovery, any advance that may have
been made will be refunded to the Customer together with interest at the rate
provided for Customer deposits under Minn. Rule 7820.4500. However, if the Customer uses less than the
guaranteed minimum, the amount of the deficiency will be billed to the
Customer. , and/or will be deducted from the Customer’s advance payment, and
the balance of the advance payment, if any, will be refunded to the Customer,
with interest on the balance.
101. The Fifth Paragraph, the Seventh Paragraph,
and the Final Paragraph contained within SECTION 5.02 Special Facilities shall
be revised to read as follows:[632]
‘Excess Expenditure’ is defined as the
total reasonable incremental cost above that of Standard Facilities, for
construction of Special Facilities, including:
the value of the un-depreciated life of existing facilities being
removed and removal costs less salvage; the fully allocated incremental labor
costs for design, surveying, engineering, construction, administration,
operations or any other activity associated with the project; the incremental
easement or other land costs incurred by the Company; the incremental costs of
immediately required changes to associated electric facilities, including
backup facilities, to ensure Reliability, structural integrity and operational
integrity of electric system; the incremental taxes associated with requested
or ordered Special Facilities; the incremental cost represented by accelerated
replacement cost if the Special Facility has a materially shorter life
expectancy than the standard installation; the incremental material cost for
all items associated with the construction, less salvage value of removed
facilities, and any other prudent costs incurred by Company directly related to
the applicable Special Facilities.
********
Common examples of
Special Facilities include duplicate service facilities, special switching
equipment, special service voltage, three phase service where single phase
service is reasonably determined by the Company to be adequate, excess
Capacity, Capacity for intermittent equipment, trailer park Distribution
systems, underground installations, conversion from overhead to underground
service, specific area or other special undergrounding, location and relocation
or replacement of existing Company facilities.
Payments required will be made on a non-refundable basis and may be
required in advance of construction unless other arrangements are agreed to in
writing with the Company. The facilities installed by the Company shall be the
property of the Company. Any payment by a requesting or ordering party shall
not change the Company’s ownership interest or rights. Payment for Excess
Expenditures associated with Special Facilities may be required by either, or a
combination, of the following methods as prescribed by the Company: a single
charge for the Excess Expenditures incurred or to be incurred by the Company
due to such a special installation, or a monthly charge being one twelfth of
Company’s annual fixed costs associated with the Excess Expenditures necessary
to provide such special installation. The monthly charge will be discontinued
if the Special Facilities are removed or if the requester eventually qualifies
for the originally requested Special Facilities as Standard Facilities. The Company shall provide to the Customer an
estimate with detail of the costs prior to construction.
********
Special Facilities Payments
Where the requesting or
ordering Customer party is required to prepay or agrees to prepay
or arrange payment for Special Facilities, the requesting or ordering Customer
party shall execute an agreement or service form pertaining to the
installation, operation and maintenance, and payment for the Special
Facilities. Payments required will be
made on a non-refundable basis and may be required in advance of construction
unless other arrangements are agreed to in writing with the Company. The facilities installed by the Company shall
be the property of the Company. Any
payment by a requesting or ordering party shall not change the Company’s ownership
interest or rights. Payment for Special
Facilities may be required by either, or a combination, of the following
methods as prescribed by the Company: a
single charge for the costs incurred or to be incurred by the Company due to
such a special installation, or a monthly charge being one-twelfth of Company’s
annual fixed costs necessary to provide such special installation. The monthly charge will be discontinued if
the Special Facilities are removed or if the requester eventually qualifies for
the originally requested Special Facilities as Standard Facilities.
102. SECTION 7.02 Modification of Rates, Rules and Regulations shall be revised to read as follows:
The Company reserves the right, in any manner permitted by law,
to modify any of its rates, rules, and regulations or other provisions now or
hereafter in effect, in any manner permitted by law. Customers shall be provided with notice of
any such modification as required by Minnesota Law and Commission Rules.
103. The Availability
Provision Contained in SECTION 10.03 LARGE
GENERAL SERVICE, shall
be revised to read as follows:
AVAILABILITY: This schedule
is applicable available to non-residential customers having a
load factor high enough to justify its application. This rate is not
applicable for energy for resale, nor for municipal outdoor lighting. Standby Service will be supplied only as
allowed by law.
A.
Removal Of Big
Stone I Acquisition Adjustment From Rate Recovery.
482. In its Application, OTP included the acquisition
adjustment for Big Stone I in its rate base.
Ms. Campbell recommended that the unamortized balance remaining in rate
base be removed. The Company agreed to
the rate base adjustment in the amount of $245,833 removing the remaining
unamortized balance of the Big Stone I acquisition adjustment from rate
base. In addition, Ms. Campbell
recommended removing the annual amortization, in the amount of $25,407, from
expenses in the 2006 test year. The
Company agrees these adjustments are appropriate because the annual
amortization included in base rates in OTP’s 1986 rate case has allowed OTP to
recover the acquisition adjustment cost.[633]
B.
Recognition of
Refund from Docket E,G-999/AA-06-1208.
483. In her Direct Testimony, Ms. Campbell proposed to
reduce the base cost of energy to reflect the Commission’s ordered refund in
Docket E,G/AA-06-1208 (“1208 Order”), which had not been issued when the
Company filed its Application. The
refunded amount in the 1208 Order is $682,982.[634] Ms. Campbell noted that this is an adjustment
to both retail revenue and production expense, with a net impact to base rates
of zero. OTP agreed to include this in
the calculation of its base cost of energy, which will be filed as part of its
compliance with the final order in this case.[635]
C.
Accumulated
Depreciation Reserve Related To 2007 Depreciation Rates.
484. In his Direct Testimony, Mr. Lusti noted that the
Company needed to increase its depreciation reserve to equal the increase in
depreciation expense of $636,397. OTP
had included the increase in depreciation expense in its Application.[636] OTP agreed this is an appropriate adjustment
to increase the accumulated depreciation reserve balance to match the
depreciation expense adjustment.[637]
D.
Big Stone
Pollution Control Equipment/Depreciation Reserve Related To Big Stone I.
485. In its January 14, 2008, Errata filing, OTP increased
the depreciation expense by $58,816, which decreased the Operating Income by
$58,816 to $280,604, reflecting the 2006 depreciation expense related to Big
Stone I. The Department offered no
objections.[638]
486. OTP forecasted its revenue for the test year as
$132,630,146. The Department forecasted
a revenue amount of $133,870,903. The
difference in these forecasts was significantly reduced through the application
of various adjustments. OTP agreed to
the Department’s adjustments to increase Retail Revenue and Production Expense
by $342,732 and $296,140, respectively.[639]
487. The Company and the Department agreed to disallow 8
of 31 advertisements that had been classified as safety advertisements because
the 8 ads did not appear to promote electrical safety. OTP and the Department further agreed that
the
488. OTP’s Application reflected $1,518,011 in CIP expenses
for the 2006 test year. The Department
testified that OTP’s proposed test-year CIP expenses were too low and
recommended increasing the expense by $247,389, which would bring OTP’s CIP
expenses to its approved 2006 budget of $1,765,400. OTP concurs with this adjustment.[641]
489. In its Application, OTP included the cash working
capital requirements for operation, maintenance, and other expenses. OTP applied lead/lag study factors to its
test-year O&M expenses to determine its cash working capital
requirement. After analysis, the
Department determined that these lead/lag factors were reasonable. The Parties agree that the lead/lag study
cash working capital calculations will need to be adjusted to reflect all of
the changes to revenue requirements as finally determined by the Commission.[642]
490. In the calculation of OTP’s federal and state income
tax expenses for this proceeding, the applicable interest deduction, also known
as interest synchronization, was calculated.
The calculation was made using the weighted cost of debt capital
multiplied by the average rate base. The
Department agrees with this method of calculation. The Parties are agreed that the interest
synchronization calculation will need to be recalculated when the final rate
adjustments approved by the Commission are known.[643]
J.
Power Services
Incentive Compensation.
491. OTP and the Department have agreed to accept the
Department’s recommendation to apply a 25% cap to the sum of the Power Service
Incentive. That application of the cap
decreases the test-year operating expense by $408,540.[644]
K.
Uncontested
Financial Related Issues.
1. The
7. The proposed
changes in tariff provisions are reasonable and should be approved.
21. OTP’s projected test year
rate base is appropriately adjusted by the Department’s D2 modifications,
reducing OTP’s transmission plant and accumulated depreciation balances for the
Based on the
foregoing Findings and Conclusions above, the Administrative Law Judge makes the
following:
IT IS
RECOMMENDED that the Public Utilities Commission order that:
1. Otter
Tail Power is entitled to increase gross annual revenues in the manner and in
an amount consistent with the terms of this Order.
2. Within
30 days of the service date of this Order, Otter Tail Power shall file with the
Commission for its review and approval, and serve on all parties in this
proceeding, revised schedules of rates and charges reflecting the revenue
requirement for annual periods beginning with the effective date of the new
rates, and the rate design decisions contained herein. Otter Tail Power shall include proposed
customer notices explaining the final rates.
Parties shall have 14 days to comment.
3. (If
the Commission orders an Interim Rate Refund) within 30 days of the service
date of this Order, Otter Tail Power shall file with the Commission for its
review and approval, and serve upon all parties in this proceeding, a proposed
plan for refunding to all customers, with interest, the revenue collected
during the Interim Rate period in excess of the amount authorized herein. Parties shall have 14 days to comment.
|
Dated: June 17, 2008 |
__s/Steve M. Mihalchick___________ |
|
|
STEVE M. MIHALCHICK Administrative Law Judge |
Reported: Shaddix and Associates
Transcripts
Prepared (Seven Volumes)
