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7/25/2019 Dorris Testimony
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North
Western
nergy
efore The Public Service Commission
f
the State
of
Montana
DOCKET NO. D2014.4.43
Petition o North Western Energy
for the Commission to Set
Terms and Conditions o Contract
between NorthWestern and Greenfield Wind LLC
REBUTTAL
TESTIMONY AND EXHIBITS
OCTOBER 2014
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13
Department of Public Service Regulation
Montana Public Service
Commission
Docket No. D2014.4.43
Greenfield
Wind
LLC Petition
NorthWestern
Energy
PREFILED REBUTTAL TESTIMONY OF
BLEAU J . LAFAVE
ON BEHALF OF NORTHWESTERN ENERGY
TABLE OF CONTENTS
14 Description Starting Page No.
5 Witness Information 2
6 Purpose of Testimony 2
17 Rebuttal
of
Prefiled Direct Testimony
of
Martin Wilde 4
18 Rebuttal
of Prefiled Direct Testimony of Don Reading
19 Rebuttal of Prefiled Supplemental Testimony of Don Reading 19
2
2 Exhibits
22 Regulation Calculation - Incremental Contracts
Exhibit_ BJL-07)
23
BJL I
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Q
3 A.
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Q
7
A.
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10 Q
Witness Information
Please state
your
name and business address.
My name
is
Bleau
J.
LaFave.
My
business address is 3010 West
69
th
Street, Sioux Falls, South Dakota 57108.
By whom are you employed and
in
what capacity
I
am
NorthWestern Energy's ( NorthWestern ) Director of Long Term
Resources
Are you the same Bleau J LaFave
who submitted
prefiled
direct
testimony
in
this docket
12 A. Yes.
13
14
Purpose
of
Testimony
15 Q
What is the
purpose
of your rebuttal
testimony
16
A.
The purpose of my testimony
is
to rebut claims made by Greenfield Wind,
17
LLC witnesses Mr. Martin Wilde and
Dr
Don Reading
in
their prefiled
18 direct testimonies and by Dr. Reading in his prefiled supplemental
19 testimony concerning the application, structure, and timing of
20
NorthWestern's avoided cost. Avoided cost for Greenfield is simply the
21 cost NorthWestern customers can void by purchasing the output from the
22
Greenfield Wind project to serve customers' load.
In
any
given
hour,
23 NorthWestern supplies its customers' load by market purchases and/or
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internal generation. The avoided cost equals the price o any avoided
purchases and/or the variable cost for any avoided internal generation.
This avoided cost must then be reduced by any increased cost derived
from the connection , delivery, and supporting service for the intermittent
Green
fi
eld project.
As shown
in
the example below,
in
any hour, the avoided cost may
represent the offset o purchases or NorthWestern portfolio generation
dependi
ng
on the amount
o
system load as it relates to the current
generation portfolio.
Illustration
Purposes Onl
y
Daily Profile Example
load Forecut _ Load ServIng Gen _ Operating Gen
1000
900
800
OF Offset Purchase Cost
7
600
500
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Q
A
Q.
A
Rebuttal of Prefiled Direct Testimony of Martin Wilde
Are you
familiar with
the Prefiled Direct
Testimony
of Martin Wilde
( Wilde
Direct
Testimony )
in
this docket
and are
you also familiar
with Mr.
Wilde's
efforts to develop
the
Greenfield
Wind
project and
seek
contracts with
NorthWestern?
Yes.
Does
the project development process described
on page MHW-3
line 2 through MHW-4Iine 15 in the Wilde Direct Testimony obligate,
as referenced
on
page MHW-6 line 11, the
project
to
provide
energy
for
NorthWestern's customers once the Power Purchase Agreement
( PPA )
is
executed?
No. If Greenfield obligated itself
to
NorthWestern, Greenfield would be
obligated to deliver the energy to NorthWestern in accordance with
NorthWestern 's avoided cost for a specific time and term. Failure to
deliver the energy would result in damage payments for not completing
the project or not delivering on time. The process described
in the Wilde
Direct Testimony describes a type of nonbinding agreement under which
developers have no obligation to provide the services under the contract
unless all other additional circumstances meet their satisfaction. His
process provides no protection to NorthWestern customers from contract
flipping , non-delivery, loss
of regulatory requirements, out-of-pocket
development costs, and integration expenses.
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Q.
A
Q
A.
Does the project development process described on page MHW-3
line 2
through
MHW-41ine 15 in the
Wilde Direct
Testimony obligate
NorthWestern
customers
once the PPA is
executed?
Yes. Once NorthWestern executes a PPA its customers are obligated to
purchase the output from the generator, and NorthWestern's customers
inherit the risks of the services not being delivered including energy
planning, market fluctuations , and portfolio planning.
Mr. Wilde claims on page MHW-6 of his
testimony
that
there were
communications with
NorthWestern prior to March
of
2014 regarding
a Greenfield project for a 25 MW Qualifying Facility (nQF ). Is he
correct?
No . The first time Mr. Wilde discussed or even mentioned a 25 MW
Greenfield QF project was his email receivedinMarchof2014 Mr
Wilde
has unsuccessfully participated in many NorthWestern Requests for
Proposals ( RFP ) and discussions concerning projects near or on this
location, but none
of these efforts directed NorthWestern to a 25 MW
Greenfield QF project. NorthWestern was never asked to provide a price
or notified that Greenfield was interested in a 25 MW QF project PPA prior
to this time frame.
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O. Does the
creation of
a 25 MW Greenfield OF project in 2014 provide
2
Mr. Wilde a basis
for
establishing a price reflecting
past
years as Mr.
3
Wilde
has
described
on pages MHW-7 and MHW-8?
4
A.
No, as mentioned above, Mr. Wilde has historically presented smaller
5
projects
on
and near this location
in
multiple configurations through
6
various formats. Some
of
these projects have been successful; some
7 have not. The limits on the size of projects qualifying for QF-1 rates would
8
not
ha
ve allowed
Mr.
Wilde to develop a project
of
this size outside
of
a
9 competitive solicitation. This exact project, a 25 MW Greenfield project,
10 was submitted unsuccessfully in a competitive solicitation for Community
11
Renewable Energy Projects ( CREP )
in
2013. It was not selected as a
2
finalist proving that the project was not financially competitive at the price
13
offered . Two other contracts at and below the rates submitted by
14
Greenfield
for
the same size projects were offered and executed.
15
16
O. On page MHW-12 starting on line 23 and continuing
to
MHW 131ine
17
4
Mr.
Wilde indicates that it is significantly more difficult
to
finance,
8 develop, and operate a CREP project than a
regular
OF. Was the
9
price
offered by
Greenfield
under
the 2013 CREP RFP process
higher
20
than
what
he has requested in
this
docket?
2
A.
No, the 25 MW Greenfield project was offered by Mr. Wilde at a rate
22
equivalent to $50.91 per MHW levelized from 2015 to 2039. The rates
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Q
A
Q
requested for this regular QF project in this docket are much higher than
what Mr Wilde submitted for this project in the 2013 RFP.
Was this project selected in the 2013 CREP RFP
process
as a
finalist
As I noted above, this project was not selected as a finalist. It was
selected as a shortlisted project. The Crazy Mountain project, which was
offered at the same rate by Mr Wilde, was selected as a finalist because it
appeared to
ha
ve less transmission risk at that time. When the Crazy
Mountain project failed to meet the Montana Public Service Commission's
( Commission ) definition of CREP, Mr Wilde offered Greenfield to fulfill
his bid proposal. Greenfield eventually backed out of its 2013 CREP
bid
that was the same as the Crazy Mountain bid with the exception that, for
Greenfield, transmission costs were identified. The additional risks
associated with these transmission costs that did not exist with Crazy
Mountain were assigned to the developer. Several weeks after
discussions
of
the project as a CREP terminated, Greenfield then
reinstated its OF request from March of 2014.
Does the rate in the PPA referenced in the Wilde Direct Testimony on
page MHW 14 starting
on
line 18 that was signed by Mr. Wilde
represent the avoided cost for a large
QF of
25 MW?
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22
A.
Q.
A.
No
. As
is
explained throughout the docket, the rates for a smaller
generation project are not the same as the rates for a larger project.
Larger projects will have greater impacts
on
the amount of ancillary
services, integration costs, and offsets to purchases
and
internal
generation. The rates identified by Mr. Wilde also do not reflect
NorthWestern s existing portfolio obligations at the time
Mr
Wilde
requested the 25
MW
QF Greenfield project. Each one of these factors
impacts the avoided cost for various types of large QF projects.
On page MHW-17 Mr. Wilde
testifies that
the
contract that
he
executed
with
NorthWestern
contained sufficient
guarantees
to
ensure performance
during
the term
of
the contract. Do
you
agree?
No. As
Mr
Wilde provides on page MHW-16 of his testimony, the
Commission order requires:
1) Price term
consistent with
the
utility s
avoided costs. (Greenfield
never asked for a price until after this filing was made. Greenfield
offered a price that was significantly above the costs that
NorthWestern can avoid by purchasing energy from Greenfield.
The avoided costs include offsetting purchases and the variable
cost of internal generation, reduced
to
account for any increase
in
integration, operation, and system upgrade costs associated with
the QF resource).
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Q
2) Sufficient guarantees to ensure performance during the term of
the contract (Greenfield's suggested letter of credit of 500,000
is significantly below the risk
of
the cost to NorthWestern's
customers because
of
the front loading
of
the levelized avoided
cost and the amount of any integration costs including regulation
and possible transmission upgrades that would need to be
contracted for or built beginning at the execution of the agreement
as identified in my prefiled direct testimony
in
this docket. Nor
would it cover the default risk associated with contracts for
additional ancillary services.
In
addition, this developer has
defaulted on several previous contracts adding additional risks to
the executed agreements and leaving NorthWestern short
of
its
CREP requirement as a result of the latest default.)
3) Demonstration of an unconditional commitment (As described by
Mr. Wilde, he first would secure the contract and then shop it
around to see if
he
could feasibly complete the project. This does
not represent an unconditional obligation
of
Greenfield to provide
the project's output. )
On page MHW-18 Mr.
Wilde testifies
that Greenfield
is entitled
to
historical QF-1 prices because NorthWestern
earlier
refused
to
negotiate on other configurations of the Greenfield project Do you
agree?
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A
Q .
A.
No . First, the Greenfield 25
MW
OF project would have never qualified as
a small OF project at any time during the period identified by
Mr.
Wilde.
The maximum size for a
OF 1
rate would have been
10
MW until recently
when it was lowered to 3 MW.
Second, Mr. Wilde has continued to negotiate with NorthWestern for
projects located
in
this area, bid into RFPs with various projects, and
restructured agreements associated with projects located in this area.
This
ffort has resulted
in
Mr. Wilde being successful
in
executing
contracts
on
at least three occasions.
Third, after
Mr.
W
il
de requested a 25 MW OF for the Greenfield project
with NorthWestern, NorthWestern filed with the Commission to seek
approval for a OF contract larger than 3 MW t NorthWestern's avoided
cost consistent with Montana statutes.
On page MHW-19 Mr. Wilde testifies th t he w s
told
the avoided
cost for the Greenfield
project
was round 50/MWH levelized. Do
you
agree?
Yes. I estimated the avoided cost for energy and capacity to be around
50/MWH. The analysis ended
up
at 48.78 as calculated using the
avoided energy and capacity costs from the projected output of
Greenfield. As I explained to Mr. Wilde, the price would then be adjusted
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Q
A.
Q
A.
in accordance with the estimated costs of ancillary services to ensure that
NorthWestern customers would not see increased costs due to the
addition
of
the Greenfield project.
On page MHW-19 Mr. Wilde testifies that he did not receive an
indicative rate for the avoided
cost
for the Greenfield project Do you
agree?
No. As Mr Wilde stated in his testimony. he did not request the indicative
pricing until the day NorthWestern filed with the Commission to review this
request. NorthWestern.
in
accordance with its tariffs,
is
unable to
negotiate a long-term bilateral contract with a QF larger than 3 MW that
was not successful in a competitive solicitation. NorthWestern efiled the
filing and served the filing on Mr. Wilde by mail the same day it was
delivered to the Commission. Therefore , the avoided cost rate was
available to him on the Commission s website no later than the day after
he requested the information , and he received the filing in the mail shortly
thereafter.
Rebuttal of Prefiled Direct Testimony of Don Reading
Are you
familiar
with the Prefiled Direct Testimony of Don Reading in
this docket?
Ye
s
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6 A.
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Q
On page OCR-4, Dr. Reading
testifi
es about the
methods
used
by
state
public utility commissions to
determine avoided cost. Has
NorthWestern ever used the method used
for
Greenfield in
determining
the
avoid
ed
cost for
a large QF
project?
I f
so,
was it
approved?
Yes. The same method for calculating avoided cost was approved
by
the South Da kota Public Utilities Commission in Order
EL
11-006.
On page OCR-5, Dr. Reading
testifies
that
the
Option
1(c) Schedule
10
QF 1 rate is the appropriate rate for Greenfield. Do you agree?
11 A. No.
The QF 1 rate
is
for projects with nameplate capacity of 3 MW or
12
less. The avoided energy and capacity costs, regulation costs, ancillary
13
costs, and transmission costs are all significantly affected by the size and
14
location of the Greenfield project, which would cause NorthWestern
15
customers to pay more under the Option 1(c) rate than could be avoided
16 by buying the output frorn Greenfield.
17
18
Q
On page OCR-7, Dr. Reading testifies
that
capacity
should
be
19
included
in
NorthWestern s
avoided
cost
calculation for Greenfield.
20
Does NorthWestern
include
a
capacity
value in
the
offer
to
21 Greenfield?
22 A.
Yes. As described
in
the Prefiled Rebuttal Testimony of Gary Dorris,
23 NorthWestern actua ll
y included 100 of the capacity value when using
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1 the forecasted first-of-month market prices that include both energy and
2 capacity value.
3
4
Q
5
A
6
Do you believe a 5% capacity value would be
appropriate
NorthWestern believes the capacity cost that can be avoided for
NorthWestern's customers by intermittent wind resources actually
7 approaches zero. However, NorthWestern concedes that 5% has been
8 directed by the Commission . The offered avoided cost could
be
reduced
9 to reflect the 5% consistent with the Commission's previous order.
10
11 Q
On page DCR-S, starting on line 7 Dr. Reading
testifies
that the
12 price methodology chosen by Greenfield is conservative. Do you
13 agree?
14
A No. The Greenfield methodology does not include the effect of the
15 hydroelectric assets in NorthWestern's portfolio. It also does not account
16 for the amount of regulation required to serve a large wind project nor
17 does it properly account for times when the NorthWestern portfolio
is
18 long and the avoidable cost for NorthWestern customers
is
the price of
19 variable generation used to serve load.
20
21 Q
On page DCR-9 Dr. Reading
testifies that NorthWestern did not
use
22 the Differential Revenue Requirement ( ORR )
method
as he
23 defines it. Do you
agree
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I A.
Yes. The DRR method as defined by
Dr
Reading does not calculate the
2
actual avoided cost for NorthWestern's customers as described by the
3
Federal Energy Regulatory Commission ( FERC ). NorthWestern used a
4
DRR method that calculates the appropriate avoided cost. Avoided cost
5
as
defined
in 18
C.F.R.
292.101(b)(6) means the incremental cost to
an
6
electric utility of electric energy or capacity or both which, but for the
7
purchase from the qualifying facility or qualifying facilities, such utility
8
wou
ld
generate
itself or
purchase
from another
source. (Emphasis
9
added.) Customers must be indifferent to whether or not the QF
is in
the
10
portfolio. QF contracts lack the benefits to customers of cost-ba
sed
rates
that are reviewed by the Commission periodically and subject custome rs
12 to increased market risks. NorthWestern customers cannot be put into the
13
position of guaranteeing a 25-year market price of energy that
is
not
14
needed to serve customer load. Providing a fixed market price for energy
15
sales effectively makes NorthWestern a broker for a QF and places the
16
associated market risk
on
customers.
17
18
Q
On page DCR-14 Dr. Reading
testifies that
the
forecast
used for the
19
Spion
Kop
Wind
Generation
sset
was different
than
what
was
20 used for Greenfield. Do you agree? If so,
what
was used for
21
Greenfield?
22
A. Yes. The forecast used for Greenfield is not equal to the forecast used for
23
Spion Kop. The forecast for the Greenfield project must be based on the
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later of the time at which
an
L
EO is
established or a large QF PPA
is
approved by the Commission. Since there is no established LEO and
Commission approval has not been completed, and because Greenfield
has no
ob
ligation to provide NorthWestern output from its project
at
NorthWestern's actual avoided cost, the forecasts will not be the same.
Even if a LEO were established earlier this year due to FERC certification
of Greenfield and the contract delivered to NorthWestern by Greenfield,
the NorthWestern portfolio w
hi
ch includes the hydroelectric assets has
changed significantly since Spion.
On page DCR18 Dr. Reading
testifies that
NorthWestern has
not
filed a large QF rate.
hy
has NorthWestern
not
filed a large QF
rate?
NorthWestern is not required to file for rates other than for small OFs
under the Public Utility Regulatory Policies Act of 1978 ( PURPA . Large
OF avoided costs vary greatly depending on location, interconnect,
resource attributes, system impacts, portfolio impacts, and ancillary costs.
On page DCR19 Dr. Reading
testifies that
NorthWestern filed a
proxy
estimate for incremental regulation
costs to fulfill
the added
regulation capacity
that will be needed for Greenfield. Is this the
most
costeffective
solution available
to
NorthWestern?
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21
No
. Since filing its petition, NorthWestern has reviewed another option for
providing regulation for Greenfield. During 2012, NorthWestern executed
two contracts for regulation services. Reflecting the cost
of
these
contracts, zonal integration rates, and the project's nameplate capacity,
Greenfield's regulation rate would be $23,944 per month escalating at
2 1 per year ($4.14 per MWH levelized over 25 years starting
in
2016)
as modeled
in
ExhibiUBJL-07).
NorthWestern has
proposed
three
different regul tion
costs
including the proposed cost above. Please describe each offer.
In
its original petition, NorthWestern submitted a regulation cost
of
$47,861 per month levelized over 25 years. This estimate was based on
the following three assumptions.
1
That the Dave Gates Generating Station ( DGGS )
is
not able to
provide additional regulation above the current capacity while
continuing to meet CPS2 requirements;
2
That the next available regulation resource would be the
expansion
of
DGGS with a fourth unit. The installation and
operational costs
of
the existing units were used as a proxy for the
costs
of
the additional unit. Greenfield is allocated costs for its
regulation requirement; and
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3
That the zonal rates for the additional wind are applicable.
2 Greenfield
is in
zone 3 with a zonal rate of
5 1
% of nameplate for
3 regulation capacity required.
5
In
response to Data Request PSC-19
in
this docket, NorthWestern
6 submitted another proposal for regulation costs at 138,354 per month
7 levelized over 25 years . This estimate was based on the following
8 assumptions:
9 1 That DGGS is not able to provide additional regulation above the
10
current capacity while cont
in
uing to meet CPS2 requirements;
2
The next available regulation resource is the expansion of DGGS
12
with a fourth unit. Wind's share of the installation and operational
l cost of the existing units were blended with the fix
ed
and variable
14 costs
of
the additional unit.; and
15
3. That the allocation to any new intermittent generation would be
16 based on 18% of the nameplate capacity.
7
18 Now as illustrated
in
Exhibit_(BJL-07) , NorthWestern proposes a
19 regulation rate of 23,944 per month escalating at
2 1
% per year. The
20 key assumptions are as follows:
21
1
That DGGS
is
not able to provide additional regulation above the
22
current capacity while continuing to meet CPS2 requirements;
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23
Q.
A.
Q.
2. That the next available regulation resource is regulation from the
market. The incremental cost is based on contracts under which
NorthWestern recently purchased regulation from the market.
New intermittent generation would receive the incremental cost;
and
3. That the zonal rates for the additional wind would apply.
Greenfield is in zone 3 with a zonal rate of 5.1 of nameplate (the
lowest zonal rate) regulation capacity required.
What was the reason for the three iterations of proposed regulation
costs
for Greenfield?
NorthWestern periodically evaluates resources in order to provide
reliable service for its customers at just and reasonable rates. The
original proposal attempted to match long-term QF contracts with a long-
term regulation resource. The second option incorporated the estimated
capital cost of an expansion at DGGS, which wasn't available for the first
option . The final proposal applies incremental costing and follows the
Commission's guidance
on
the application
of
zonal rates for regulation
of
wind resources.
On page DCR-24 Dr. Reading
test
ifies
that although
Greenfield has
selected
to
keep the renewable energy
credits
( REC , Greenfield
should get some
credit for
being Green .
Do you agree?
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A
Q
A
Q
A.
No. If Greenfield keeps the RECs NorthWestern customers will be paying
for intermittent brown power from Greenfield. There would be no green
attributes to be offset for NorthWestern customers and no benefits
to
NorthWestern customers. As identified
in
PURPA NorthWestern
customers must only pay for costs that can be avoided. Greenfield will
receive all the value associated with the project from the retained
renewable credits.
Rebuttal of Prefiled Supplemental Testimony of Don Reading
Are you
familiar with
the Prefiled Supplemental Testimony of Don
Reading in
this docket
Yes.
On
pages
DCR-5 and DCR-6 Dr. Reading
testifies that NorthWestern
is required to use the ORR method as he as defined it. Do you
agree?
No. NorthWestern
is responsible for calculating the costs that can be
avoided for load service to its customers. This cost is easily and
transparently calculated by the amount of offset purchases and offset
generation minus additional costs incurred due to the specific project.
o
other cost can be avoided by purchasing output from Greenfield . By
definition that
is
what must be considered in the avoided cost
calculations.
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Q
On page DCR-6 and DCR-7 Dr. Reading testifies that the avoided cost
2
price should include
opportunity
sales and a future inclusion
of
a
3
combined
cycle
combustion turbine
(UCCCT ) in NorthWestern's
4 portfolio Do you agree?
5
A. No FERC has ruled that sales are not
to
be included
in
the avoided cost
6
calculation. If this were allowed, NorthWestern customers would become
7 a risk broker for any wind project regardless of the needs of
8
NorthWestern . As discussed above, the off-system sales are not part of
9
the costs
to
serve customer load and are not
to be
included in the avoided
10
cost calculation. Additionally, the future CCCT that
Dr
Reading is
I I
requesting to be included
in
the model, according to him, increases the
12
future costs over the market comparison. If the CCCT is included in the
13
model as Dr Reading suggests, NorthWestern customers will pay an
14
artificially high price for future
po
wer Under an economic dispatch model,
15
the plant would not
be
running because the market price is lower. The
16 only cost that could be avoided by customers under this scenario is the
17
market price.
18
19
Q
Does this conclude
your
testimony?
20
A
Yes, it does.
BJL 20
7/25/2019 Dorris Testimony
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Capacity MW)
Percentage
Regulation Capacity MW)
e Per MW)
per
Month)
Capactiv Factor
Output MWh)
Reg Cost S/MWh)
Year
Levelized Regulation)
Ene rgy/Capacity Cost
Rate
$
$
$
$
$
$
w.li
2016
25 25
5%
5
1.3 1.3
220,719
$
225,355
281,417
$
287,327
23,451
$
23,944
38.23% 38.23%
83,735 83,735
3.36
$
3.43
4.14
50.91 12016 thru 2040
7.14%
2.1%
ost $46.77 12016 thru 2040
$
$
$
$
2017
25
5%
1.3
230,087
$
293,361
$
24,447
$
38.23%
83,735
3.50 $
Bleau,
2018
25
5%
1.3
234,919
$
299,522
$
24,960
$
38.23%
83,735
3.58 S
2019
25
5
1.3
239,852
$
305,811
$
25 484
$
38.23%
83,735
3.65 S
2020
25
5%
1.3
244,889
$
312,234
$
26,019
$
38.23%
83,735
3.73
$
202 1
25
5
1.3
250,032
$
318,790
$
26,566
$
38.23%
83,735
3.81 S
2022
25
5
1.3
255,282
$
325,485
$
27,124
$
38
.23%
83,735
3.89
$
he inflationilryescilliltionrate
used
in the 2013 Plan was 2.1% (Vol 1, Ch 6. p. 6-25).
odd
Guldseth, Todd
nt:
Monday, July
14,2014
1:03
PM
0: Steve lewiS s)[email protected])
: laFave, Bleau; Fine,
David
E
ubject: RE:
Rate
2023
25
5
1.3
260,643
$
332,320
$
27,693
$
38.23%
83,735
3.97
$
r e us ed NWE's m a
rgi
nal cos t of cap ital re lated
to th
e hydro ac
qui
sit ion of 7.14%
to
lev
eli
ze re sou rces
in
he
2013
Pl
an, so I
wo
uld
sugges t using th at.
2024
25
5
1.3
266,117
$
339,299
$
28,275
$
38.23%
83,735
4.
05
$
2025
25
5
1.3
271,705
$
346,424
$
28,869
$
38.23%
83,735
4.14
$
Docket No. 02
01
4.4
Exh
ibi t_ BJL-
2026
25
5
1.3
277,411
$
353,699
$
29,475
$
38.23%
83,735
4.22 S
Page 1 o
2027
25
5
1.3
283,237
361,127
30,094
38.23%
83,735
4.31
7/25/2019 Dorris Testimony
23/105
=
Q 2
2030
2031
=
Ql2
Plate Capacity (MW) 25 25 25 25 25
25
5 5 5 5 5 5
(MW)
1.3 1.3 1.3
1.3
1.3 1.3
MW)
S
289, 185
S
295,258 301,458 307,789
S
314,252
S
320,851
S
l Regulation Cost
368,710 376,453
38
4,359 392,430
S
400,671
S
409,086
Contract
(
per
Month) 30,726 31,371 32,030 32,703 33,389 34,090
recasted Capactiy Factor 38.23
38.23 38.23
38.23
38.23 38.23
r
ecasted
Output (MWh)
83,735 83,735 83,735
83,735 83,735
83,735
Reg
Cost
(S/ MWh)
4.40
4.
50 4.59 4.69 4.79
4.89
Year Level ized (Regu lati
on)
Energy/Capacity Cost
on (Regulation
Rate)
ost
2034
2037
25
25 25
25
5 5
50'
5
1.3 1.3 1.3
1.3
327,589
S
334,469 341,493
S
348,664
417,676
S
426,448 435,403
S
444,546
34,806 35,537 36,284
37,046
38.23
38.23 38.23 38.23
83,735 83,
735 83,735 83,735
4.99 5.09 5.20
5.31
2038
fQJ
25 25
5% 5
1.3 1.3
S
355,986 363,462
453,882 463,413
37,823 38,618
38.23
38.23
83,735 83,735
5.42
55
Doc
ket N
o.
020
14
.4
hibi t_(BJL-0
Page20
2040
25
5
1.3
371,094
S
473 ,145
39,429
38.23
83,735
5.65
7/25/2019 Dorris Testimony
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Docket No. 02014.4.43
Exhibit_(BJL-07)
Page30fS
NWE bisting Wind Facilities Under Contract and Required Regulation Capacity
per
QF-1
Wind In tegration Zonal Rates
NorthWestern Energy - Dave Gates Generating Station
Wind Integration I Fixed Cost Rate
Facility
Jud ith Gap
I
Horseshoe Bend
I
Small
QF
Projects
2
Gordon Butte
Sp ion
Kop
Musselshell
Musselshell 2
Fairfield
Two Dot Wind Farm
Existing Wind Total
Inc. Additional Wind
Greenfield
Greycliff
New
Co
lony
New Wind Total
Total
Nameplate
Capacity
Zone (MW)
2
3
2
1
3
1
3
2
2
135
9
4.0
9.6
40
10
10
10
9.7
237.3
2S
20.4
2S
. 70.4
307.7
Note
1 Based
on Genivar Study: Senario (A-B)
Regulation as
% 01
Nameplate
Capacity
27.1
5.1
14.0
S.1
14.0
38.0
5.1
38.0
5.1
14.0
14.0
Note 2 - Included in system data in the Genivar Study
[N THE MATTER OF the NorthWestern Energy
s
Application for Approval of Avoided Cost TarifTfor
New Quali f
ying
Facilities
Required
Regu
lation
Capac i
ty
(MW)
36.5
0.5
1.3
2.0
1.4
3.8
0.5
3.7
49.8
1.3
2.9
3.5
7.6
57.4
Supply Load Integration Capacity
(MW)
Supp
ly Wind Integr
ation
Capacity (MW)
Total Supply Integration Capacity (MW)
Transmission Load Integration Capacity
(MW)
Total Integration Capacity at eGGS (MW)
REGULATORY DIVISION
DOCKET NO. 0 20
12
.1.3
ORDER NO. 7199d
Table
6.
Approved
long-term wind
integration rates
IINMd ..
_-.:I ..kw_
l2-poice
.. ....
/ l . u poo P C-OD2I.l
ul Md Z I _ye_
. 200-1InI_T_Z. -a .ood . Z.1lt.:poo_
. . . ._
DGGSWind
Integrati
on
Fixed
Costs
42
45
87
18
105
7/25/2019 Dorris Testimony
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-
Wind Power
Scenario apaci ty
Name
IMW)
Scenario Description
144
Existing
wind
resources
for the
historical study
period:
135
W at
Judith Gap and 9 MW at Horseshoe
Bend
B
0
All wind r
esources
removed
C 154
cenario Awith one 10 MW project added
near
Judith
Gap
in Wheatland County
C2
154
cenario A
with
one 10 MW
project
added distant from
udith Gap in
Madison County
C3 154
Scenario Awith one
10
MW
project
added
distant from
udith Gap in
Glacier
County
1
194
:Scenario A with one 50 W project
added
near
Judith
Gap
in
Wheatland
County
2 194
Scenario Awith one
50
MW project added distant from
udith Gap in Madison County
3 194
Awith one
S
MW
project
added distant from
udith Gap in
Glacier
County
Scenario
A
with one
17.s MW
project
added in Madison
4
194
County
one 17.5
MW project added in Wheatland
County
and one 15
MW project added inGlacier
County
A
with
four 10 MW
projects
and
four
2.5 MW
5
194
projects
diversified
from
each other and
from
Judith
Gap
El 294
cenario Awith one 150 MW project
added
near Judith
Gap in Wheatland County
E2
294
cena
r
io
Awith one 150 MW project added distant
rom
Jud ith Gap in Madison County
E3
294
cenario
Awith one 150 MW project added distant
rom Judith Gap in
Glacier
County
E4 294
cenario
Awith a
50
MW project added in
each of the
ollowing counties:
Madison Wheatland
Glacier
cenario Awith one 50 MW project two 25 MW
E5 294
projects and
five 10 MW projects diversified from each
o
ther and
from
Judith Gap
Scenario
Awith two 150 MW projects
one
50 MW
F
594
project
three 2S
MW projects
and
two 12.5 MW
projects dive rsified from
each other
and from Jud ith
Sensitivity 1
294
E5 w
ind
with
30-minute
wind forecasting
Sensitivity
2
294
E5
wind with wind
curta i
lment
Sensitivity 3 294 fScenario E5 wind with intra-hour supply adjustment
GENIVAR v
Docket No. 02014.4.43
Exhibit_IBJl-07
Page 4 of 5
Required Regulating
Reserve
Ran ge
for Targeted Performa nce MW)
of
94 CPS2
of
92 CPS2
110 96
69
59
113.8
97.1
108.7 92.6
109.2 94.6
136
117
112 97
120
101
120
101
105
95
209 181
149 130
163
144
144 126
132
114
223
194
114 98
114 94
119
100
June 1, 2011
7/25/2019 Dorris Testimony
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NorthWestern Energy
Estimated Additional Regulation Costs
(Pat
Di
Fronzo)
Based on
A
vista Contract
in
Year 2 12
Avista Contract up to 5MW
Capacity
Energy
Trans
mi
ssion L
osses
Point to Po int T
ra
nsmi
ssion Serv
ice
Total Monthly Cost
Based o Powerex Contract;n Year 2 12
Capacity
BP
A Transmission
BC
HA Tranmission
Serv
i
ces
(a) Total Capacity Cost
(b) M
ax
imum Rate
(c) Capac
it
y Charge Enter the Lesser of (a) or (b) rate
Energy Charge
Total Charge
Total Costs
fo r both Contracts (Monthly)
Total Costs
fo
r both Co ntracts An
nu
ally)
Cost Per MW (Annua
ll
y)
7.62
23.65
24 .65
2.00
8.00
1.501
4.610
14.1106
15.00
14.
11
23.65
S
pl
it
50 Av i
sta
Docket No . 0 2014.4.43
Exhibit_
61L
-07)
Pa
ge
5 of 5
50 Powerex
12,419
1
KW Caeacitl l
kw -month
6,209 47,315
Mwh
2,235 52,866
67 1,653
kw mon th
6,209
12,419
114,252
kw-month
6,209
49,674
9,320
28,622
87
,617
93,140
1 87,617 1
Mwh
- 1,123 1 26,549 1
1 114,166 1
[ - 228,419 1
1 2,741,62
7
I 220,719
1
March 2012 Invoice
I
50,000
75
0,000
_
227,263 1 30.30%1
977,263
7/25/2019 Dorris Testimony
27/105
1
2
3
4
5
6
7
8
9
10
12
13
Department
of
Public Service Regulation
Montana
Public
Service
Commission
Docket No. 02014.4.43
Greenfield Wind LLC Petition
NorthWestern Energy
PREFILED REBUTTAL TESTIMONY OF
DAVID
E
FINE
ON
BEHALF OF NORTHWESTERN ENERGY
TABLE OF CONTENTS
14
Description Starting
Page No.
15
Witness
Information
1
16
Purpose
of
Testimony
3
17 Rebuttal of Prefiled Direct
Testimony
of Martin Wilde
3
18 Rebuttal
of
Prefiled Direct
Testimony of
Don Reading
10
19 Rebuttal
of
Prefiled Supplemental
Testimony
of
Don Reading
11
20
21 Witness Information
22 Q.
Please state
your
name and
business
address.
23
A
My name is David E. Fine and my business address is
40
East Broadway
24 Street Butte Montana 59701.
25
26 Q.
By
whom
are
you
employed and in
what
capacity
DEF l
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2
3
4
5
6
7
8
9
10
11
12
13
14
IS
16
17
18
19
20
21
22
23
A.
Q
A.
Q
A
I am employed by NorthWestern Energy ( NorthWestern )
as
Director
of
Energy Supply Planning.
What
are your
responsibilities
and
duties
in your
current
position
My areas of responsibility include a variety of energy supply and planning
functions including the preparation of the electricity supply resource
procurement plan and associated analysis, load and resource analysis,
load forecasting, and other supply portfolio planning and management
functions performed
by
pl
anning staff.
n
addition, I
am in
volved
in
regulatory matters associated with the electricity supply portfolio ,
resources, contracts, and NorthWestern's retail electricity supplier
obligations.
Please
describe
your educational
background
and experience.
I earned a Bachelor of Arts degree in Geology from the University of
Montana and have worked
in
the energy industry since 1979.
I began employment with the utility in 1982 with an unregulated subsidiary
of the Montana Power Company. I have worked
in
energy exploration and
development, mining, energy resource evaluations, economic evaluations,
business development, and technical evaluations associated with energy
production and power generation. Since 2003 I have worked
in
the
Energy Supply area where
I currently oversee planning activities including
DEF 2
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1
2
3
4
5
6
7
8
9
Q
10
A
12
13
14
15
16 Q.
17
18
19
A.
2
21 Q
22
tasks such as the preparation of the electricity supply resource
procurement plan and other long-term procurement planning and analysis.
As an employee of NorthWestern I have previously provided information
and testimony on energy and utility-related matters before the Montana
Public Service Commission ( Commission ).
Purpose of Testimony
What is the purpose of your
testimony
in this proceeding?
The purpose
of
my testimony is to (i) rebut certain statements and
assertions contained in the Prefiled Direct Testimony of Martin Wilde, and
(ii) rebut certain statements and assertions contained in the Prefiled Direct
and Prefiled Supplemental Testimonies
of
Don Reading.
Rebuttal of Prefiled Direct Testimony of Martin Wilde
Are you
familiar
with the Prefiled
Direct
Testimony
of
Martin Wilde in
this docket and with Mr. Wilde's efforts to develop the Greenfield
wind
project and seek contracts
with
NorthWestern?
Yes.
What have you
concluded
with regard to Mr.
Wilde
's accounts
of
his
efforts
to
secure
a
long term Qualifying Facility
(
QF
) wind resource
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2
3
4
5
6
7
8
9
1
2
3
14
15
16
7
8
9
2
2
22
23
A.
Power Purchase Agreement ( PPA ) as described in his prefiled
direct
testimony?
Beginning on page MHW-6 Mr. Wilde describes a series of events and
certain (but not all) communications between NorthWestern and
Greenfield Wind, LLC ( Greenfield ).
Mr.
Wilde's recounting of events
confirms that NorthWestern consistently and correctly administered the
then-current Commission approved OF-1 tariffs. NorthWestern acted
appropriately when Mr. Wilde requested standard long-term OF wind
project rates for projects that clearly did not meet the conditions necessary
under the approved and then-applicable tariff schedules.
Mr. Wilde portrays NorthWestern as blocking all attempts by Greenfield
to obtain a OF wind contract. He includes statements such as being in
continuous contact with NorthWestern since 2010 and refers to that
thick exhibit of correspondence as evidence of NorthWestern's lack of
responsiveness or willingness to process the Greenfield OF contract
submissions. Contrary to Mr. Wilde's assertion that NorthWestern was
uncooperative, the voluminous communications, and exchanges of
information establish NorthWestern's cooperation and reasonableness.
NorthWestern acted within its responsibility
to
address Mr. Wilde's
inquiries regarding both OF and Community Renewable Energy Project
(
CREP ) contracts.
DEF-4
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1
Q
From the
second quarter
2010 through 2012 when NorthWestern
was
2
exchanging PPA proposals as
described
by Mr. Wilde, what
was
,
NorthWestern
seeking
to accomplish through
the
exchanges?
4 A. NorthWestern was seeking to incorporate commercially reasonable terms
5 into its supply contracts, including any such contract that it might enter into
6
with
Mr.
Wilde. The development of the commercial terms was viewed as
7
necessary to standardize contracts by using industry standard practices
8
and conditions not only for QF contracts but to maintain standards of
9
acceptable commercial performance across all supply sources. Mr. Wilde
10 describes his efforts as attempting to obligate NorthWestern to a contract
with Greenfield. NorthWestern was fi rm in presenting commercial terms
12
that would uphold reasonable standards of performance for both parties
13
and to ensure that contracted resources, including Greenfield, would meet
14
their obligations.
15
16
Q
Mr.
Wilde
states that he sought 10-MW long-term, fixed rate QF wind
17
contracts for
both
Fairfield Wind, LLC (
Fairfield )
and Greenfield.
18
Did
his
request
result
in an executed
contract(s)?
19 A. Yes. Ho wever, at the time the Fairfield agreement was executed,
20
NorthWestern was obligated under the terms
of
the Commission-approved
21
QF 1 Tariff not
to
exceed
50
MW of new
QF 1
wind capacity. Execution of
22
a 10-MW contract for the Greenfield project would ha ve exceeded the
23
50-MW cap and therefore NorthWestern was
no
longer able to offer a
DEF
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1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
Q
A
Q
long-term fixed rate contract for Greenfield
or
any other 10-MW QF wind
project that would cause the
50-MW cap to be exceeded.
In
this regard
Greenfield was being treated the same as other developers who no longer
had the opportunity to enter into a contract under the long-term fixed rate
option.
Mr. Wilde
indicates
that
Fairfield was pressured
into
entering
into
a
PPA
Did NorthWestern pressure or
somehow try to
compel Mr.
Wilde
to
enter
into
a
contract?
No.
NorthWestern believes the pressure described by Mr. Wilde was the
knowledge
by
developers including
Mr.
Wilde that
if
a developer did not
acquire a contract prior to NorthWestern reaching the 50-MW cap they
would not have
an
opportunity to seek a long-term fixed rate for a 10-MW
QF project with NorthWestern until terms of the
QF 1
Tariff changed
regarding the 50 -MW cap. Anyone with knowledge of the QF 1 Tariff at
that time was aware of the 50-MW cap. NorthWestern clearly
communicated to developers interested
in
developing QF wind projects
that the installed contract capacity available for projects was
on
a first-
come first-served basis until the cap was met.
Following
the
execution
of the
original
Fairfield
Wind contract
Mr.
Wilde
states that
a
second contract
for Fairfield
Wind was
signed.
Why
was
a
second
contract necessary?
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2
3
4
5
6
7
8
9
10
12
3
14
A.
15 Q
The first contract was terminated by NorthWestern for Fairfield's breach of
the contract. Prior
to
terminating the contract NorthWestern agreed to
allow
Mr.
Wilde additional time (60 days) to post a delay security deposit
of 200,000. NorthWestern made this concession as a good faith gesture.
After Fairfield failed to post delay security NorthWestern exercised its right
to terminate which gave Fairfield an additional 1O day period
to
cure the
breach of contract. Delay security is
an
example of a commercial term
used by NorthWestern to provide assurance that developers and project
owners w ill meet their contractual obligations under conditions of financial
penalty
if
they fail to perform. If no security is posted by a developer in
conjunction with its contractual obligations, then the developer is free to
violate the terms of the agreement without penalty or recourse by
NorthWestern, just as Fairfield did with its original contract.
Was Mr. Wilde pressured into executing the second Fairfield contr ct
16 following the
termin tion
of
the
first agreement?
17 A
18
19
No. Notice of termination was sent on March 5, 2012. Notice of available
OF wind contract capacity under the 50-MW cap was distributed to
potential OF developers, including Mr. Wilde ,
on
March 8, 2012.
20 Following redlined document exchanges, a second PPA with Fairfield was
21 fully executed
on
March 28, 2012 less than a month following th e
22 termination of the first agreement. This re-established Fairfield Wi
nd
as
23 the last 10-MW OF wind project under the 50-MW cap.
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2
3
4
5
6
7
8
9
10
12
13
14
15
6
7
8
9
20
21
22
23
Q
A
Q
A
Mr. Wilde
describes
NorthWestern as blocking Greenfield attempts to
obtain a
10
-MW
long term
QF wind contract. Do you agree? If
you
do
not
agree, please explain.
No I do not agree with Mr. Wilde s assertions that NorthWestern attempted
to block or impede Greenfiel
d.
NorthWestern has presented and
defended its position regarding the QF 1 Tariff provision, which, at the
time, limited new QF wind contracts
to 50
MW of installed nameplate
capacity. This is clearly shown
in
Exhibit MHW-03 containing schedules
for the
QF 1
Tariff beginning
in
May 2010 and extending through 2013.
During this time NorthWestern was never in the position to waive or ignore
the
QF 1
Tariff and offer a 10-MW contract to Greenfield .
Did Greenfield
offer to
sell
the project to
NorthWestern
as
a
build
transfer? If
it
did,
how did
NorthWestern
respond?
Yes. Following the execution of the first Fairfield QF contract
in
the first
quarter of 2012, Mr. Wilde asked NorthWestern to consider purchasing the
project as a turnkey CREP project. During the course of discussions with
Mr. Wilde, NorthWestern communicated the need to use competitive
solicitations for CREP acquisitions to ensure that least-cost, least-risk
resources are acquired. At no time did NorthWestern offer to purchase
the project using a bilateral process. NorthWestern simply reviewed
project materials to gain a better understanding of the project at Mr.
Wilde s request.
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Q
A.
Mr. Wilde states on page MHW-12 lines 11-14 that NorthWestern has
consistently
taken the
position that
the developer must take the risk
of
approval
of
the
CREP
structure
even
though
MPSC
Staff
has
informed us
on several occasions
that
the administrative rules
require NorthWestern to petition for
certification
of
the CREP
project
prior to the execution of the PPA.
e
goes
on
to
say on lines 15-16
that
this
is another example of
how
NorthWestern
consistently
uses
its
bargaining
power to
place unreasonable
risks
on
project
developers.
Are Mr.
Wilde's
complaints valid? Please explain.
CREP eligibility is a developer risk regardless of whether the CREP
certification petition for the project is submitted to the Commission by
NorthWestern or by the developer/owner. NorthWestern will not take
CREP eligibility risk nor should it be charged with defending and arguing a
CREP project developer's potentially complex ownership structure before
the Commission. In the case where NorthWestern has selected a project
to help meet its CREP obligations, it is appropriate to place the CREP
eligibility responsibility on the developer who exercises ownership control
and has its financial interests to protect. Except for its own resources,
NorthWestern exercises no control over the ownership
of
CREPs.
Additionally, NorthWestern exercises no control over the Commission in
terms of it determining whether or not a project is CREP eligible, and
therefore has no bargaining power
to
assert concerning the approval
of
a
project as CREP.
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Q.
A
Rebuttal
of
Prefiled Direct
Testimony of
Don Reading
Dr. Reading
concurs with Commissioner
Travis
Kavulla's conclusion
in
Order
No. 7199d, Docket No. 02012.1.3
that
a
5
capacity
contribution established by
the
Commission
adequately
accounts
for
wind's
intermittency. But
then
Dr
. Reading
goes
on
to
state
that
using
only a
5 capacity factor
due to wind's
intermittency produces
a
low
avoided
cost
rate
that
could
reasonably
be
higher under
different
reasonable
assumptions.
Do you agree
with
these
statements?
I agree that a 5% capacity contribution was determined as appropriate for
Montana wind resources eligible for standard offer contracts by the
Commission. I do not agree, as Dr. Reading suggests, that a higher
capacity value should somehow be attributed to the Greenfield project.
To
support his claim, Dr. Re ading
al
so suggests that in other parts of the
country the capacity contribution of wind resources
is
higher than 5% but
offers no specific evidence as to why a Montana wind resource should
receive higher capacity credit. His statement concerning a higher avoided
cost rate that could reasonably be higher under different
re
asonable
assumptions
is
not supported by any evidence provided
in
this docket.
Based
on
a clear lack of ev idence
to
justify a capacity value in excess of
5% for Montana
wi nd
resources and the fact that the Commission has
previously ordered a 5% wind capacity contribution for some OF projects,
assumption of a higher capacity value is not justified.
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Rebuttal
of
Prefiled Supplemental
Testimonv of
Don Reading
2 Q
Dr. Reading references a Federal Energy Regulatory
Commission
3
decision Hydrodynamics
146 FERC 1161,193 (2014) regarding the
4 utility
obligation
to
purchase any
capacity
which
is made available
5
from
a QF at a rate that, at the QF s
option
is a forecasted avoided
6
cost
rate. What
capacity
does NorthWestern
understand that
7
Greenfield
is
proposing to
sell?
8
A
It is NorthWestern s understanding that Greenfield will sell the full output
9
of the facility as a bundled energy-capacity product to the extent a nominal
1
capacity contribution exists. A capacity value in excess of what is already
being included
in
the Greenfield Wind QF rate is not justifiable. The
2
calculation of avoided costs for Greenfield includes the price of offset
13
market purchases which have a substantial associated capacity value.
4
The market rates used by NorthWestern and Ascend Analytics, LLC
in
the
15
calculation of avoided costs have not been discounted to account for the
6 lower capacity value of the wind energy. In this case, Greenfield enjoys a
7
high implied capacity value
by
virtue of the market purchases for which it
8
is displacing and receiving credit.
Any additional wind capacity
9
consideration is not appropriate.
2
2 Q Dr. Reading states
that
it would be reasonable for the
Commission to
22 consider
the
supply portfolio
at
times
prior
to
2014 and
to somehow
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incorporate this information
into
its deliberations concerning the
2 Greenfield rate. Is this appropriate
If
not, please explain.
3
A.
No
, it would not be reasonable to consider
Dr
Reading's assertion.
In
the
4 absence
of
the Hydros, the addition
of
a combined cycle combustion
5 turbine ( CCCT ) may have been plausible as early as 2018. However, in
6 April of 2014, when Greenfield asserted it had created a legally
7 enforceable obligation for a 25-MW project, and after the submission of
8 the 2013 Electricity Supply Resource Procurement Plan, NorthWestern
9 was anticipating and planning for the addition
of
the hydroelectric assets
10
and was not planning for the addition of a CCCT in 2018.
12 Q
Dr. Reading argues
that
the addition of a eeeT should be included
13 for
consideration
in the
calculation of
avoided
cost
rates.
Should
14 NorthWestern consider a eeeT to be avoidable compared
to
the
15 addition
of
a
wind resource
16
A.
No . These two resource types have completely different attributes that
17 must be taken into consideration. A wind project provides intermittent
18 energy and a minimal capacity contribution. A CCCT provides load-
19 serving capacity and dispatchability. For load-serving and resource
20 planning purposes a wind resource could not be reasonably substituted for
21
a CCCT that provides capacity, dispatchability, and flexibility.
22 Q
23 A
Does this
conclude
your testimony
Yes it does.
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Department
of Public Service Regulation
Montana Public Service Commission
Docket No. D2014.4.43
Greenfield Wind
LL
Petition
NorthWestern
Energy
Prefiled Rebuttal Testimony of
Gary W. Dorris
on Behalf of NorthWestern Energy
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Table
of
Contents
I: Witness Infomlation ............
...........................
...........
..
..................................................... 3
II: Overview
of
Testimony .......................................................
..................
....
....................
5
III: Overview
Of
Analysis Detennining Greenfiel
d s
Avoided Cost Rates .................
....
........ 6
IV. Results .................................. ................. ..........
.......................................................
............. 13
V. Ratepayer Risk ......... ..
...... ......................... ..... .....
.
...............
.......................
.............
17
VI: Greenfi eld Access to 'PowerSimm ................................
.......................
......... ..........
.....
19
VII: Conclusions .......................................................................
.....
..........................................
20
List of Figures
Figw'e
1.
Average Avoided Cos
ts
..........
..................................................................
................
14
Figure
2
Wind generation a
ll
ocation between market sales and purchases ................................
15
Figure
3
Total
po
rt
fo li
o net pos ition with and without Greenfield .......................... .......... ........ .
16
List
of
Tables
Table
1
Avoided Cost
of
Capacity in
1MWh ............ ........ ................................. ...... ........ 17
Exhibits
Exhibit GWD- l -
Illustrations
of Avoided Cost
Scenarios
Exhibit GWD-2
- Avoided
Cost
Su
mmary Table
Exhibit GWD-3
-
Curriculum
Vitae
of
Gary
W.
Dorris
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I: Witness Information
Please
state your
name occupation and address.
My
name is Gary W. Dorris. I am the Chief Executive Officer of Ascend Analytics,
LLC. Our headquarters are at 1877 Broadway Street, Suite 706, Boulder, CO 80302. We
have additional offices at 222
E
Main, Suite 201, Bozeman,
MT
59715 and 440 Grand
Avenue, Suite 360, Oakland,
CA
94610.
Please summarize
your
educational and
professional
background.
I am founder and
Chief
Executive Officer ( CEO )
of
Ascend Analytics. Ascend
Analytics is an energy analytics software and consulting company that provides
economic, financial, and technology solutions for the energy industry, particularly in the
area
of
portfolio risk management, energy supply procurement, asset valuation,
quantitative modeling, and complex litigation. I have led the growth
of
Ascend to one
of
the foremost energy analytic companies in the country, providing software solutions to
three
of
America's top five largest utilities to address portfolio management,
ri
sk
analytics, and planning strategies.
I have been involved in the energy industry for over
25
years and have extensive
expenence rn counseling corporations rn complex decision analysis, portfolio
management strategies, and risk management. I have also provided independent expe
lt
reports to support the valuation and frnancing
of
over $5 billion in electric generating
assets. I have written and delivered expert testimony regarding risk management, energy
procurement, trading practices, asset valuation, market power, and emissions trading. I
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have also led the analytic architecture of over ten analytic software products used by 30
of the top 100 energy companies.
Before founding Ascend Analytics, I served as CEO and Chief Model Architect for e-
Acumen, a 60 person energy consultancy and software analytics fmn. I have also
directed the development
of
the analytic infrastructure and risk management policies for
the launching of the
tradi og
floors of Entergy Solutions, Duke Solutions, The Energy
Authority, and Consolidated Edison, and led the development
of
the analytic
i..ofrastmcture solutions for portfolio and risk management solutions at over a dozen other
utilities. I have traded power and structured power sales contracts and completed one of
the first above cost power transactions in the U.S. in 1988.
I was also a faculty member at Comel University in 1996, where I taught a doctoral-level
cowse
i o
modeliog competitive energy markets, and have been adjunct faculty at
University of Colorado's Leeds Business School from 1997 to 2007. I have published
papers on energy trading and risk management i o peer-reviewed scholarly journals, and
have spoken at over 50 conferences on resource planning, portfolio management, risk
analysis, and modeling of competitive energy markets.
I
hold a Ph in applied
economics and finance from Comell University and both a BS
i o
mechanical
engi oeeri og
and a BA
i o
economics with Magna Cum Laude disti..oction from Cornell University.
Futther details on my qualifications are set
fOlth
in my CutTiculum Vitae (Exhibit GD-3).
I reserve the right to update and supplement my expert testimony
as
may be necessary.
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II Overview of Testimony
On whose behalf are you testifying in this proceeding?
I am testifying on
behalfof
NorthWestern Energy ( NorthWestern or the Company ).
Please
summarize your testimony.
My
testimony substantiates the economic constmct to detelmine the avoided cost
calculations for Greenfield and its consistency with PURPA and FERC regulatory
guidelines. Through substantiating the economic constmct and presentation
of
modeling
result
s,
I will rebut the testimony
of
Dr. Don
C.
Reading concerning the appropliateness
of the methodology and use
of
PowerSinun software. n paJiicular, I will address the
following issues:
I)
The economic constmct
of
the differential revenue requirements approach and its
suitability to determine the avoided cost of energy to
se
r
ve
load.
2) The flawed economic reasoning in Dr. Reading's argument that the avoided cost of
energy would increase
by
utilizing
an
optimal capacity expansion plan or adding a
combined cycle plant in some future year to NorthWestem's portfolio.
3) The consistency
of
the modeling approach with FERC mlings.
4) The lisk to ratepayers related to the purchase
of
Greenfield generation stenuning
from:
a
95% excess payment for capacity not delivered and b) violation
of
FERC's
ratepayer neutrality principal
by
leaving customers wor
se
off
with the QF
purchase, and c) use of the marginal unit
of
generation for 25 successive years to
establish avoided costs
of
energy.
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Q.
A
Q.
A.
Q.
The economIC arguments and analysis presented below fully substantiate the
determination of avoided costs for Greenfield.
Please outline the remainder of your testimony.
Section III provides an overview of my analysis to determine the avoided cost of energy
and capacity. Section
IV
presents results
of
the avoided cost analysis for Greenfield.
Section V discusses the risks
to
ratepayers related
to
contracting with Greenfield. Section
VI
reviews Ascend offers
to
collaboratively support Greenfield's modeling interest
through access
to
PowerSi.J.mn.
Section VII provides concluding remarks.
III
Overview Of Analysis Determining Greenfield's Avoided Cost Rates
What analysis have you done that
supports
your testimony?
I
have perfonned
an
economic analysis to detennine the avoided cost
of
energy
to
serve
N011hWestem's customer load through the purchase of Greenfield.
I
applied the
PowerSilmn software under the same assumptions and inputs used to eva
lu
ate the
Hydros. These assumptions were inclusive of the cost of carbon on NorthWestem's own
generation and market prices, load, fuel prices, and the inclusion of the Hydros in
NorthWestem's supply portfolio. Additional detail on the modeling assumptions can be
found in N011hWestem's
2013
Electricity Supply Resource Procurement Plan ( 2013
Plan ).
Why
did
you apply PowerSimm and the same modeling
construct
to determine
Greenfield's avoided cost rates as was used to evaluate the Hydros?
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A
Q.
A.
Q.
We performed the analysis of Greenfield s avoided cost rates directly after completing
the 2013 Plan. Levera ging the modeling framework of the Plan was in accordance with
best practices because the Plan established a credible set
of
long-term modeling
assumptions and had undergone a ligorous set of validation exercises. Subsequent to our
analysis
of
Greenfield
s
avoided cost rates, the PowerSirnm modeling framework
received best practices designation from a critical peer review by Evergreen
Economics. I
How exactly was the avoided cost rate calculated?
Ascend applied economic anal
ys
is that would fall under FERC' s Di ffe rential Revenue
Requirement ( ORR ) approach to detennine the avoided cost of energy to serve
NorthWestem load. Because PowerSimm applies a chronological dispatch model, we
were able to determine the avoided cost to serve NorthWestem load on an hourly basis.
For each hour, we determined avoided costs to serve load as the maxinmm
of: i
the
marginal cost of the highest cost available generating unit to serve load or ii) the market
price
of
energy purchased to serve load. The maximum hourly cost between these two
components detennines marginal cost of production for each hour and the avoided cost of
energy to serve load.
Is the
hourly
avoided cost
approach the same
as
the RR approach
to serve load?
I
Evergreen Economics, Review of
NorthWeste
rn s Application
to
Purchase Hydroelectric Facilities, page ii
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A
Yes, the DRR approach looks at the difference between the cost to serve load with and
without the asset in question
2
Because
we
rue applying cluonological dispatch logic
instead
of
a more simplified model constmct
of
load duration curves we can determine
the avoided cost on an hourly basis by utilizing the hourly generation output.
In
addition,
PowerSimm automatically optimizes generation to serve load with respect to market
oppOltunities to buy and sell power. To determine the avoided cost to serve load during
surplus conditions, the mruginal cost
of
production is the marginal cost unit in
NorthWestern's supp ly stack to serve load. During conditions of export sales the
mruginal unit serving NorthWestern ' s load is invariably Colstrip Unit 4.
Q.
Would it be
possible
under
the DRR approach applied
here
for the
avoided cost
to
be higher with the inclusion of
an
additional resource?
A. No, the addition of a combined cycle ( CC ) plant or any other plant would
unconditionally leave the avoided costs received by Greenfield the same or lower.
Exhibit
GWD I
provides six cases, consisting
of
t1uee cases where NorthWestern sells
power, and three cases where NorthWestern purchases power. The illustrations
of
Exhibit GWD-I demonstrate that Greenfield would receive the same or a lower avoided
cost of energy with the introduction of an additional generating resource.
For example, ifNOIthWestern was selling power, the avoided cost remains the marginal
cost
of
generation serving load. The addition
of
a new unit with a marginal cost higher
than Colstrip would not change the cost of serving load. The addition of a new unit with
: Mathematically, the approach taken is akin to determining the slope
of
a line through a first derivative point
estimate versus the difference between two x and y values around the point estimate.
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Q
A
a lower marginal cost than Colstrip would decrease the cost of serving load. As an
additional example, ifNOIthWestem was buying power from the market, the avoided cost
could be lower
if
the new plant could offset market purchases with a marginal cost
of
production less than the market price. If the new plant had a cost of production higher
than the market price, the avoided cost would remain unchanged and NOIthWestem
would continue to purchase energy from the market.
Under no circumstance would the avoided cost be higher with the addition of a new
generating plant. f a higher avoided cost was produced by adding a generating resource,
then it would suggest the economic analysis did not optimize the generation dispatch
effectively. The
cUlTent
avoided cost methodology provides the maximum hourly price
to selve load. The addition of a new generating unit will apply downward pressure on the
calculated avoided cost to selve load.
ow would utilizing
n
optimal capacity expansion plan
imp ct
the avoided cost of
energy?
The use of
an
optimal capacity expansion plan hearkens back
to
the earlier days of
PURP A when competitive power markets did not exist. Under today s construct where
the market provides the avoided cost
of
energy, there
is no
need
to
provide
an
optimal
capacity expansion plan because of the existence of a market price forecast.
n
order for
NOIthWestem to add a resource, it must improve upon the economics over market
purchases (and reduce risk and increase reliability). The development of
an
optimal
capacity expansion plan will lower the avoided cost of energy to selve load. Whether the
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Q.
A
Q
resource addition follows an optimal capacity expansion plan or has been arbitrarily
selected, the economics of optimal dispatch to serve load will not increase the avoided
cost
of
energy
to
serve load. The economic rationale for this conclusion follows the
principals discussed in the question above and the analysis shown in Exhibit GWD-I.
Does the price forecast for
power
include both
an
energy and a capacity cost?
Yes, the price forecast for power is constlUcted of two pa11s: 1 near-term fOlward market
prices and
2
long-term fundamentally forecasted prices. Both price forecast components
contain a capacity component. The fOlward market binds energy and capacity together
through contractual
tem1S
requiring finn delivery
of
energy with liquidated damage
penalties for failure
to
de
li
ver. The long-tenn forecasts
of
the forward curve for power
is
developed
to
adhere to long-nm equilibrium conditions based on the variable and fixed
costs of a new CC plant. Long-run equilibrium conditions are maintained through adding
a new CC plant
to
the p0l1folio after the end of the visible p0l1ion of the fOlward curve
for power is available. Long
-lU
n equilibrium conditions are measured by checking the
CC' s gross margin revenues realized from economic dispatch against the plant's
levelized fixed operating costs. The gross margin revenue from economic dispatch
should on average over a ten-year period cover the fixed operating expenses of the CC.
Equilibrium conditions are satisfied when on average the gross margin revenues yields a
normal return on capital for the plant.
Would
it be
appropriate to modify the avoided cost of capacity from a generic
combustion turbine ( CT )
to
a generic CC?
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A.
Q
A.
No, capacity provides for physically fum delivery
of
energy. The value
of
capacity
is
measured as the levelized fixed cost for a relatively inefficient plant that operates
at
a
relatively high marginal operating cost but has low capital cost. We have used the fixed