20040426Post Hearing Brief.pdf

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STATE OF IDAHO ( C ,,
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BEFORE THE PUBLIC UTILITIES COMMisSI6~ hi; 'j. ,
IN THE MATTER OF THE APPLICATION
OF IDAHO POWER COMPANY FOR
AUTHORITY TO INCREASE ITS INTERIM
AND BASE RATES AND CHARGES FOR
ELECTRIC SERVICE
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CASE NO. IPC-O3-
BRIEF OF THE KROGER CO.
I. INTRODUCTION
On October 16 2003 , Idaho Power Company ("the Company ) filed an Application with
the Idaho Public Utilities Commission ("Commission ) for authority to increase the Company
general rates an average of 18 percent. If approved, Company revenues would increase by nearly
$86 million annually. Idaho Power provides electric service to approximately 405 000
residential, commercial, industrial and irrigation customers in southern Idaho including The
Kroger Co. ("Kroger ). Kroger operates 11 retail grocery and general merchandise facilities in
the state of Idaho served by the Company. These stores purchase more than 30 million kWh of
electricity from the Company annually.
Kroger submits this Brief in support of its argument that: 1) If any rate increase is applied
to Rate 9, the same percentage increase should be applied to Rates 9-, 9- P, and 9- T so that a
reasonable, cost-based price differential is retained among them; 2) time-of-use rates should be
available to Schedule 9 customers, so that these customers could better respond to price signals
as well as pay rates that are more closely aligned with the costs they cause; 3) Kroger generally
agrees with the Company s proposal to weight any rate increases relatively more heavily on the
demand charge, as opposed to the energy charge, for those rate schedules with demand meters;
and 4) the Commission should modify the Company s proposed rate cap for the Irrigation class if
an overall base-rate increase of less than 18 percent is approved and gradually phase in a rate
increase to the irrigators over the next several years in order to align Irrigation class rates with
cost of service and relieve the burden borne by the other classes that are subsidizing the
Irrigators.
II. ARGUMENT
If Any Rate Increase Is Applied To Rate 9. The Same Percenta!!e Increase Should
Be Applied To Rates 9-S. 9-P. And 9- So That A Reasonable. Cost-Based Price
Differential Is Retained Amon!! Them That Reco!!nizes That Takin!! Service At
Primary Volta!!e Is Less Expensive For The Utility To Serve Than Takin!! Service
At Secondary Service.
Staff has recommended a 0.13 percent rate reduction for Rate 9-S and a 13.31 percent
rate increase for Rates 9-P and 9-T. Although Kroger generally agrees with Staff that cost-of-
service analysis should be given a very strong weight in detennining rate spread, it is also
important to have a rational pricing regime within rate schedules.Staff's recommendation
contains a serious flaw (perhaps unintended) because it results in primary voltage customers
paying almost the same rate as secondary voltage customers.
In the case of the relationship between secondary and primary service within a rate
schedule (such as between 9-S and 9-P) it is important for prices to indicate that for any given
customer taking service at primary voltage is less expensive for the utility to serve than taking
service at secondary service. Unfortunately, Staff's rate spread proposal for Rate 9 would cause
the price differential between primary service and secondary service to all but disappear. This
result would not only lead to irrational pricing within Rate 9, it would be punitive to customers
who invested in the necessary transfonner equipment to take primary service based on the
current price differential. By making the investment in such equipment themselves, primary
service customers allow the utility to conserve capital, slow the growth in distribution system
rate base, and absorb less line losses. All across the country these utility cost savings result in
primary service being less expensive than secondary.
The price differential between Rates 9-S and 9-P under current rates and under Staff's
proposed rates is shown in Attachment A. The analysis utilizes hypothetical customers of
various sizes and load factors. A summary of these results are shown in the Table below.
Table 1
Comparison of Rates 9-S and 9- P
(Positive % indicates Primary is less expensive than Secondary)
Current Primary Staff Proposed
Customer Discount Primary Discount
500 kw, 45% l.f.9.41 %61 %
500 kw, 60% l.f.11.20%54%
500 kw, 75% l.f.12.41 %84%
750 kw, 45% l.f.87%07%
750 kw, 60% l.f.11.57%0.11 %
750 kw, 75% l.f.12.72%1.21 %
1000 kw, 45% l.f.10.1 0%1.80%
1000 kw, 60% l.f.11.78%11 %
1000 kw, 75% l.f.12.87%1.39%
The above Table shows that under current rates, primary service is about 9 to 13 percent
less expensive than secondary for any given customer. But under Staff's proposal , this
differential is virtually eliminated. In fact, in many cases, primary service would actually become
more expensive than secondary. This abnonnal result could not have been intended since nearly
I Higgins, Rebuttal Testimony, p. 4. lines 1-20.
equalized prImary and secondary rates is contrary to customary and standard ratemaking
principles.
Staff Exhibit No. 127 does show that under its proposal, the average price per kWh for
Rate 9-S would be 3.645 cents per kWh, and the average price per kWh for Rate 9-P would be
369 cents per kWh. At first glance, this infonnation might appear to contradict the Table
above. However, there is no contradiction. The lower average price for Rate 9-P reflects the
larger size and higher load factor of the average customer in this group relative to Rate 9-
These same customers would have lower-than-average rates if they were on secondary service
as well, given their load characteristics. The problem is that under Staff's proposal , for each of
these primary customers individually, the primary and secondary rates would become almost
indistinguishable, even though for each of these customers, primary service is less expensive to
provl e.
Primary service is less expensive to provide than secondary service for two main reasons:
(1) Primary service requires fewer utility-provided facilities, as primary customers provide their
own transfonners , thereby reducing the amount of utility capital expenditures needed to provide
distribution service; and (2) primary service incurs fewer line losses to the customers' meter
meaning that for each hundred kilowatt-hours delivered to a customer s meter, the utility needs
to generate fewer kilowatt-hours to serve a customer on primary service than on secondary
service. On Idaho Power s system, the line loss differential between primary and secondary
service is about 3 percent.
1 Higgins Rebuttal Testimony, p, 4, lines 23-33,3 Said Workpapers, pp. 3-
It is clear that primary service is less expensive to serve than secondary, even though the
cost-of-service study produced a result that lead Staff to propose raising Rate 9-P so much that
the differential between Rate 9-S and Rate 9-P disappears. Cost-of-service analysis allocates
system costs to groupings of customers based on a seri'es of allocation factors. Generally,
allocation factors are intended to capture infonnation about the pattern of usage of each customer
group taken as a whole, such as relative usage during a monthly system peak hour. During the
test year, the Rate 9-P group, taken as a whole, exhibited a usage pattern that was allocated a
greater increase in cost responsibility relative to current revenues than Rate 9-S. This was due, in
part, to a higher per-unit allocation of production costS.
As noted above, it is important to have a rational pricing regime that recognizes that for
any given customer taking service at primary voltage is less expensive for the utility to serve
than taking service at secondary service.
It is also important to recognize that, theoretically, for any sub-group of Rate 9, a cost-of-
service allocation could be perfonned that would produce results that varied from the results for
Rate 9 as a whole. These results would reflect the mix of customers in the sub-group. An
important question, then, is whether the most appropriate criteria are being used to define the
sub-group. For example, it is useful to avoid categorizing customers into relatively small sub-
groups of otherwise similarly-situated customers. Smaller groups tend to have less diversity with
respect to their coincident peaks and their non-coincident demands. A lack of diversity adversely
impacts the per-unit charges derived for the group from the allocation of peak-related costs.
4 Higgins, Rebuttal Testimony p. 5, fines 15-20; p, 6. lines 1-2, See Also, Idaho Power Exhibit No, 42 , pp, 4-
In addition to providing time-of-use prIce signals, which is addressed below, it is
important that customers be grouped, for cost-of-service purposes, in a manner that minimizes
the likelihood of anomalous results.
In the case of Rate 9, the customer qualifications to take service under Rates 9-, Rate 9-
, and Rate 9- T are identical, except for the voltage level at which service is taken. In addition
Rate 9-S is a much larger group than either 9-P or 9- T. In this situation, allocating a demand-
related function (such as production) to Rate 9-P separately from the rest of Rate 9 might lead to
anomalous results.
Rates 9-, 9-, and 9-should be combined and a reasonable, cost-based prIce
differential should be retained among them. This price differential would recognize that for any
given customer taking service at primary voltage is less expensive for the utility to serve than
taking service at secondary service.
Attachment B summarizes Kroger s proposal to combine Rates 9-, 9-, 9-T. The same
overall revenue requirement to the aggregate of 9-, 9-, and 9-T is applied as in the Staff's
recommendation, but is spread on an equal percentage basis across the entire Rate 9. This results
in a 1.16 percent increase on all the Rate 9 customers. This approach would retain a reasonable
price differential between Rate 9-S and 9-P. Kroger recommends that this modification to Staff's
Rate 9 rate spread be adopted by the Commission.
Time-Or-Use Rates Should Be Made Available To Schedule 9 Customers. In Order
For These Customers To Better Respond To Price Si2nals. And To More Closely
Ali2n Costs With The Cost-Causers.
5 Higgins, Rebuttal Testimony, p, 7, lines 1-
Time-of-use rates should be available to Schedule 9 customers, so that these customers
could better respond to price signals, as well as pay rates that are more closely aligned with the
costs they cause. Idaho Power is proposing mandatory time-of-use rates for Schedule 19 in order
to send improved price signals to customers. The Company also has an optional time-of-use rate
for Irrigation service that is in place on a pilot basis. However, the Company neither has, nor
proposes, any time-of-use options for Schedule 9 customers, who represent 26 percent of the
retail energy consumed on the Idaho Power system.
Energy costs vary across the hours of the day, with the most expensive hours typically
occurring from the late morning to early evening. Designing the energy price to end-use
customers to reflect these variations in energy costs sends the proper signal to customers
regarding the relative cost to operate the system during the peak, mid-peak, and off-peak hours.
Customers would then use this pricing infonnation to alter their discretionary patterns of usage
increasing efficiency and lowering the overall cost of energy to the system.
As Schedule 9 customers represent over a quarter of the retail energy consumption on the
Idaho Power system, the failure to offer time-of-use rates to them deprives this class of
customers of the opportunity to save money by responding to appropriate price signals. It also
deprives the system of the benefit of a more efficient load pattern that would result from this
responsive behavior. Basic fairness also dictates that customers whose patterns of energy
consumption are less expensive to serve than the average in their class should see that lower cost
reflected in their bills. Idaho Power is moving in this direction for Schedule 19. The Company
should also take steps in this direction for Schedule 9.
6 See Idaho Power Exhibit No, 43, p, I , co!. 3,
Time-of-use rates are widely available throughout the west for customers of comparable
size to Schedule 9. Table KCH below is a partial list of other western utilities that offer time-
of-use rates to customers with billing demands of 1000 kw of less, comparable to Schedule 9.
Table KCH-
Western Utilities with Time-of-Use Rates for Customers with
Billing Demands of 1000 kw or less
State Utility Type
Arizona Arizona Public Service Pilot*
Arizona Salt River Project Optional
Arizona Tucson Electric Power Optional
California LADWP Optional .c500 kw
California LADWP Mandatory :;0.500
California PG&E Optional .c500 kw
California PG&E Mandatory :;0.500
California SDG&E Optional .c500 kw
California SDG&E Mandatory :;0.500
California So. Cal. Edison Optional .c500 kw
California So. Cal. Edison Mandatory :;0.500
California SMUD Mandatory
Colorado Public Service Colorado Optional
Nevada Sierra Pacific Optional
Oregon PacifiCorp Optional
Oregon Portland General Optional
Utah PacifiCorp Optional
* Permanent TOU rate proposed in pending rate case
In Idaho, PacifiCorp offers an optional time-of-use rate, but the rate design only
differentiates between on-peak and off-peak demand - not energy. As such, it should not be
incorporated here.
Due to the certain difficulty in mandating an immediate change to time-of-use rates
Schedule 9 time-of-use rates should be made available for the upcoming rate-effective period on
a voluntary basis. At a minimum, such a rate should be offered as part of a pilot program, which
7 Higgins Testimony, pp, 9-10.
could be used to gather infonnation on the price responsiveness and benefits derivable from
expanding time-of-use rates more broadly to Schedule 9 customers. This voluntary time-of-use
option for Schedule 9 should offer peak, mid-peak and off-peak energy prices that properly
reflect time-of-use cost differences. It is not necessary to add the complexity of the two-tiered
demand charge that the Company is proposing for Schedule 19.
The Commission should order the Company, as part of any compliance filing in this case
to file a voluntary time-of-use rate for Schedule 9 customers that provides peak, mid-peak, and
off-peak energy prices that properly reflect time-of-use cost differences. A general rate case is
the best time to adopt a new time-of-use rate, as it allows for the full consideration of the revenue
effects that accompany the creation of a new rate schedule. In addition, Idaho Power has noted
its increased gas price risk in recent years associated with purchased power, with the attendant
higher energy costS.8 It is important to take appropriate rate design steps now, rather than
delaying. If it is another ten years until the next Idaho Power rate case, and this issue is simply
deferred for later action, the opportunity to send efficient price signals for Schedule 9 customers
could be delayed a decade.
Kroger Supports The Company s Proposal To Wei2h Any Rate Increases Relatively
More Heavily On The Demand Char2e.
Kroger generally agrees with the Company s proposal to weight any rate increases
relatively more heavily on the demand charge, as opposed to the energy charge, for those rate
schedules with demand meters. Weighting any increase toward the demand charge would tend to
8 See, for example, pre-filed direct testimony of J, LaMont Keen, p, 5, line 21 - p, 6, line 20,
reflect the composition of the Company s underlying costS.9 For this reason, if there is an
increase, weighting it toward the demand charge is preferable to weighting it toward the energy
charge.
The Commission Should Modify The Company s Proposed Rate Cap For The
Irri2ation Class If An Overall Base-Rate Increase Of Less Than 18 Percent Is
Approved.
Idaho Power proposes a significant subsidy to the Irrigation class. According to the
Company s cost-of-service analysis, it would require a 67 percent increase in Irrigation base
rates for this class to fully recover its costs if the Company s requested overall base-rate increase
of 18 percent is approved.1O To mitigate the impact of the base-rate increase for this class, the
Company proposes to cap the Irrigation increase at 25 percent, with the difference spread to the
other rate classes. Although it is reasonable to cap rates in order to mitigate the impact of a large
rate increase for a deeply subsidized customer class, the Commission should modify the
Company s proposed rate cap for the Irrigation class if an overall base-rate increase of less than
18 percent is approved. Additionally, the Commission should gradually phase in a rate increase
to the irrigators over the next several years in order to align Irrigation class rates with cost of
service and relieve the burden borne by the other classes that are subsidizing the Irrigators.
In its request for an 18 percent rate increase the Company proposes to cap the Irrigation
base-rate increase at 25 percent, with the difference spread to the other rate classes. I I Capping
the base rate increase at 25 percent for any customer class for the purpose of limiting rate shock
is reasonable. However, it is also important to adopt additional guidelines for spreading rates in
9 Idaho Power Exhibit No, 42, See Also Pre-filed direct testimony of Maggie Brilz, p, 50, lines 18-25,10 Higgins, Testimony p, 4, lines 5-II IPCEx, No. 61.
the event that the Commission reduces the Company s proposed overall rate increase. In that
case, the base-rate increase to the Irrigation class should be capped at 25 percent, or twice the
system average increase, whichever is less. This would retain the 25 percent cap proposed by the
Company, but would also apply a sliding scale to the Irrigation class increase that would lessen
the amount of the subsidy to the extent the rate increase is smaller than proposed by the
Company. So, for example, if the Commission approved an overall base-rate increase of
percent, the base-rate increase to the Irrigation class would be capped at 20 percent.
Additionally, the Commission should take steps toward eliminating the subsidy to the
Irrigation class by adopting a multi-year phase-in toward cost of service rates. This could be
accomplished by setting a cost of service target and taking incremental steps toward that target
over several years. Specifically, Kroger recommends a rate plan that moves Irrigation base-rates
one-third of the way to full cost of service rates in three steps over three years, measured from
the initial rates approved in this proceeding. The revenue from the annual adjustments would be
used to alleviate the subsidy paid by the other rate classes by reducing their rates on an equal
percentage basis each of the three years. For example, the maximum phase-in adjustment would
occur if the Company s proposed base-rate increase of 18 percent is adopted. This case is
illustrated in Attachment C. In this case, Irrigation customers would require a 67 percent base-
rate increase to move to cost of service rates, but would only receive a 25 percent initial increase.
Movement to full cost of service rates would require another 42 percent increase, one-third of
which is 14 percent. The latter would represent the phase-in target, which would be reached in
three installments over three years of 4.7 percent per year.
The revenues from the 4.7 percent annual phase-in would be used to reduce the subsidy
from other classes, amounting to a .67 percent annual base-rate decrease for those classes each
year, for a cumulative base-rate reduction of 2 percent.
It is imperative that the Commission set a plan into action that will reduce the subsidy to
the Irrigation class over time rather than revisiting this issue in the Company s next rate case.
There is no assurance that a rate case will be filed in the next three years. Indeed, it has been
about ten years since the last Idaho Power rate case. Locking in a significant subsidy for an
indefinite period of time is not reasonable to the customer classes providing the subsidy and is
counter to the fundamental consideration of rate making; cost of service.
Kroger is well aware that the Commission has traditionally discounted cost of service
studies as inherently inaccurate and a balance of art and economic principles 12 due to the
perception that a cost of service study can be easily manipulated to align to a party s interest
rather than actual cost-causation. This view of cost-based rates is in the distinct minority given
the near-universal belief among other regulatory bodies!3 and scholars that cost-causation be the
primary consideration in setting rates.
True, other factors of ratemaking are potent and are sometimes
controlling
...
(bJut the cost standard has the widest range of
application. Rates found to be far in excess of cost are at least
highly vulnerable to a charge of unreasonableness, Rates found
11 IPUC, Case No, WWP-98-, Order No, 28097, p, 27 (1999),
13 Cost allocation is simp~v an attempt to spread costs among various customer classes on the basis of afactor that
is close~v correlated with the incurrence of costs Re: Kentucky Utilities Co" 15 FERC ~61 ,222 (1981), The
Commission s long standing practice has been to base class revenue allocations on the cost-of-service, Re:
Central Il1inois Light Co" 158 PUR 4th I (Illinois PSC 1994), See also Connecticut Power and Light, 144 PUR 4th
161 (Connecticut Department of Public Utility Control, 1993) (Commission moved all rates of return closer to
company average thus reducing cost-of-service differentials and improving the state s business climate); Re Niagara
Mohawk Power Corp" 140 PUR 4th 481 (New York PSC, 1993) (Commission approved rate design based on cost-
of-service study which resulted in residential rate increase of 5.8% versus industrial rate increase of 1.4%);
North Carolina Power, 142 PUR 4th 117 (North Carolina PUC, 1993) (utility was directed to realign its rates to
move toward equalized rates of return. Accordingly, residential customers were assigned a greater portion of the
rate increase than the large power customers who had already been paying in excess of their share of costs),
well below cost are likely to be tolerated, if at all, only as a
necessary and temporary evil. For if rates are not compensatory,
they are not subsidy free. In fact, the golden rule of socially
optimal ratemaking is that, whenever possible, prices should track
all ident(fiable
...
costs occasioned by a service s provision.
James Bonbright Principles Of Public Utility Rates pp. 109-110
( 1988)
***
major goal of cost allocation is the avoidance of cross-
subsidization between classes of customers
...
A cardinal rule of
ratemaking is that where cross-subsidization is practiced, it should
be wittingly practiced, rather than unwittingly or accidentally, and
fully supported by reasoned decision making.Leonard Saul
Goodman The Process Of Ratemaking p. 374 (1998).
This is not to say that Idaho Commission precedent turns a blind eye to cost of service in
setting rate. When the evidence is clear that one group of customers is subsidizing another, as it
is in this case Commission precedent dictates that such subsidies should be eliminated or
dramatically cut back. In Case No. IPC-94-5 the Commission articulated its rule concerning
proper rate allocation when there is reliable evidence of cross-subsidization between classes.
Recognizing that cost-ofservice studies are not precise, we think
it important that cross subsidies among customer classes should be
minimized. Accordingly, as outlined below we take significant
steps to move each class closer to its indicated cost-o.fservice.
Order No. 25880 at. 34 (1995).
The phase-in approach detailed above accomplishes the worthwhile goal of blunting the
initial impact on an under-recovering class, while continuing to move toward cost-of-service
rates over time. If a rate case is filed during the phase-in period, then any rates approved from
that case should supercede the phase-in rates, as of the rate-effective period associated with the
new case.
III. CONCLUSION
Kroger argues that 1) If any rate increase is applied to Rate 9, the same percentage
increase should be applied to Rates 9-, 9- P, and 9- T so that a reasonable, cost -based price
differential is retained among them; 2) time-of-use rates should be available to Schedule 9
customers, so that these customers could better respond to price signals, as well as pay rates that
are more closely aligned with the costs they cause; 3) Kroger generally agrees with the
Company s proposal to weight any rate increases relatively more heavily on the demand charge
as opposed to the energy charge, for those rate schedules with demand meters; and 4) the
Commission should modify the Company s proposed rate cap for the Irrigation class if an overall
base-rate increase of less than 18 percent is approved and gradually phase in a rate increase to
the irrigators over the next several years in order to align Irrigation class rates with cost of
service and relieve the burden borne by the other classes that are subsidizing the Irrigators.
Respectfully submitted
~~~
Michael L. Kurtz, Esq.
Kurt J. Boehm, Esq.
BOEHM, KURTZ & LOWRY
36 East Seventh Street, Suite 2110
Cincinnati , Ohio 45202
Ph: 513-421-2255 Fax: [phone]
e-mail: mkurtzlaw((l),aol.com
April 23 , 200
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Kroger Rebuttal Exhibit No. 904
Case No. IPC-03-
K.C. Higgins
3/19/04
Summary of Schedule 9 Rate Spread Using
IPUC Staff's Proposed Revenue Requirement
Schedule No,
STAFF PROPOSED STAFF PROPOSED KROGER PROPOSED
Large Large LargeGeneralGeneralGeneral
Service Service ServiceSecondaryPrimary & Trans.Total
9P & 9T 9S, 9P & 9T
17,299 116 415
667,376,237 347 050 749 014 426 986
349,138 10,319 874 107,669 012
(123 369)373,312 249,943
97,225,769 693,186 108 918 955
13%13,31%16%
2003 Average No. of Customers
2003 Sales Normalized (kWh)
Current Base Revenue ($)
Staff Proposed Final Rev. Adjustments ($)
Staff Proposed Base Revenue ($)
Percent Change
Data Source: IPUC Staff Exhibit No. 127 (D. Shunke)
Attachment B
Line
No,Tariff DescriDtion
Uniform Teriff Rates
Residential Service
Small General Service
Total Large General Service
Dusk to Dawn Lighting
Large Power Service
Agricultural Irrigation Service
Unmetered General Service
Street Lighting
Tralllc Control Lighting
Tolal Uniform Tariffs
Special Contracts
Micron
J R Simplot
DOE
Tolal Specia' Conlracls
Tolalldaho Relall Sales
D818 Sources:
1. IPCo Exhibit No, 43, p, 1 0122
2. IPCo Exhibit No, 41
Not8:
3. Annual adjustment lor 3 years,
Example of Three-Year Phase-In Toward Cost-of-Service Rates
Using Idaho Power's Proposed $86 Milljon Base Rate Increase
NDnn.,~.d 12.Monl.s ending Dmmbe. 31, 20D3
(1)(2)(3)(4)(5)(6)(7)(8)
CDS CDSRateCurrentCDSCDSIPCo Proposed IPCo Proposed Phase-in Phase,Sch.Bese Revenue Percent Revenue Percent Annual AnnualNo,Revenue ustments Chanqe ustments Chanae ustment ustment ISI
214,289,414 666,058 13,38%40,786,881 19,03%67%426,221)798,476 563,674 15,26%529,614 21.01%67%(111 804)107,669 012 10,309,059 57%194270 15,04%67%(716,600)389,106 412,294)101,67%69,323 99%67%(9,245)063,573 660 409 46%639 707 13,87%67%(366,480)291 575 456,288 67,10%078,364 25,01%68%819,769907,689 (221 178)24,37%45,246 98%67%(6,041)809 269 (267,473)14,78%90,219 99%67%(12,042)284,14S 21,332 51%36,598 12,88%67'10 11,8911
458,502 259 84,775,875 18,49%470 222 18,20'10 04'10 169445
16,204 104 465,070 87%296,405 00%67%(107,848)632,571 (82 642)78%144 341 12%67'10 (30 832)622 414 403,609 73'10 654 392 67'10 1307651459,089 786 037 09%095 138 23%-0,67%(169 445)
483 961 348 561,911 17,68%85,565360 17,68%00%(0)
KROGER EXHIBIT NO, 2
CASE NO, IPC-03-
K, C, HIGGINS
PAGE 1 OF 1
Attachment C