Dorris Testimony

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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3 A.

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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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A

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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.

BJL 5


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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

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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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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).

BJL 8


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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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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

BlL IO


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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

B1L l1


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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

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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


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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Q

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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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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1

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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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.


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.

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


22/105

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


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


24/105

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


25/105

-

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


26/105

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


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


28/105

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


29/105

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

DEF 3


30/105

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


31/105

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

5


32/105

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?

DEF 6


33/105

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.

DEF 7


34/105

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.

DEF-8


35/105

2

3

4

5

6

7

8

9

1

I I

12

13

14

5

16

17

8

19

2

21

22

23

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.

DEF-9


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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.

DEF I O


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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

DEF

II


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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.

DEF 12


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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

Documents

Dorris Testimony