20120629Park Rebuttal.pdf

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BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE COMMISSION'S
REVIEW OF PURPA QF CONTRACT
PROVISIONS INCLUDING THE SURROGATE
AVOIDED RESOURCE (SAR) AND
INTEGRATED RESOURCE PLANNING (IRP)
METHODOLOGIES FOR CALCULATING
PUBLISHED AVOIDED COST RATES.
CASE NO. GNR-E-11-03
IDAHO POWER COMPANY
REBUTTAL TESTIMONY
OF
TESSIA PARK
I
1 Q. Please state your name and business address.
2 A. My name is Tessia Park and my business address
3 is 1221 West Idaho Street, Boise, Idaho 83702.
4 Q. Are you the same Tessia Park that submitted
5 direct testimony in this proceeding?
6 A. Yes, I am.
7 Q. What is the purpose of your rebuttal
8 testimony?
9 A. My rebuttal testimony responds to a variety of
10 issues raised in the direct testimony of intervenors in
11 this case, including a response to various criticisms
12 related to Idaho Power Company's ("Idaho Power" or
13 "Company") proposed Schedule 74 as well as other Schedule
14 74 and operational related issues.
15 I. IDAHO POWER'S PROPOSED SCHEDULE 74
16
Q. The Direct Testimony of Idaho Wind Partners I,
17 LLC ("Idaho Wind Partners") witness Richard Guy is critical
18 of how Idaho Power proposes to implement Schedule 74,
19 Policy and Procedure for Operational Dispatch of Certain
20 PURPA Qualifying Facilities, because it "lacks the
21 specificity to determine the specific circumstances in
22 which Idaho Power could cease purchases . . . ." From an
23 operations standpoint, why is it difficult to determine
24 when Schedule 74 would apply?
25
PARK, REB 1
Idaho Power Company
1 A. Although the operational and system conditions
2 that must exist before Schedule 74 would apply are clearly
3 spelled out in Schedule 74 and match the operational
4 conditions set out by the Federal Energy Regulatory
5 Commission ("FERC") for the applicability of 18 C.F.R. §
6 292.304(f), it is impossible to predict with perfect
7 accuracy how often those operational conditions would occur
8 on Idaho Power's system and thus how often Idaho Power's
9 proposed Schedule 74 would impact Public Utility Regulatory
10 Policies Act of 1978 ("PURPA") generators operating on
11 Idaho Power's system. The factors that influence this
12 include the total amount of intermittent, unscheduled
13 Qualifying Facilities' ("QF") generation on the Company's
14 system, the delta between the minimum and maximum load on
15 the Company's system, and hydro conditions.
16 Q. Is it possible for you to estimate how often
17 Schedule 74 would apply to QFs on the Company's system?
18 A. As I explained earlier, it is impossible to
19 predict with perfect accuracy how often the Company would
20 need to apply Schedule 74. However, based upon the current
21 amount of intermittent generation currently on the
22 Company's system as well as based on recent, historic, and
23 near-term forecasted load and generation data for Idaho
24 Power's system, in my professional opinion and based upon
25 my experience in overseeing the Company's Grid Operations,
PARK, REB 2
Idaho Power Company
1 I would estimate that on an annual basis, the use of
2 Schedule 74 would impact QF generators on the Company's
3 system less than 5 percent of the time. In other words,
4 for QFs on the Company's system, Schedule 74 would result
5 in relieving Idaho Power of the obligation to purchase less
6 than 5 percent of the total annual generation it purchases
7 from QF5.
8 Q. Is this estimate a long-term estimate?

9 A. No. This estimate is based upon what I
10 believe would occur based upon current conditions on Idaho
11 Power's system. This estimate could be higher or lower
12 over time based upon the addition of more intermittent
13 generation on the Company's system and various changes in
14 hydro conditions as well as system load.

15
Q. The Direct Testimony of Dynamis Energy, LLC's

16 ("Dynamis") Richard Looper is critical of the Company's
17 proposed Schedule 74's applicability to the QF project
18 because its project is not an intermittent resource. What
19 is your response?

20 A. Unlike the vast majority of other QF projects
21 on Idaho Power's system, generation from the Dynamis
22 project is non-intermittent in nature. Because its
23 proposed project is a fueled, thermal-based resource,
24 Dynamis would have the ability to shape and deliver energy
25 from its project. However, it is my understanding that
PARK, REB 3
Idaho Power Company
1 during the negotiations for the Firm Energy Sales Agreement
2 between Idaho Power and Dynamis that Dynamis would not
3 agree to make the energy from its project dispatchable
4 unless Idaho Power agreed to pay a very high price for that
5 dispatchable energy. Idaho Power did not believe that
6 those high prices would be in the best interest of its
7 customers so it was unable to reach an agreement on the
8 dispatchability of the energy form this project. That
9 said, Idaho Power did agree to pricing and terms that would
10 provide an incentive to Dynamis to deliver energy to Idaho
11 Power during heavy load hours. However, since Dynamis does
12 not provide Idaho Power with scheduled deliveries, it is
13 possible that during certain times of the year, Dynamis
14 will be delivering energy to Idaho Power during heavy load
15 hours when the Company does not need that energy to serve
16 load. Like any other PURPA QF, Dynamis controls when, if,
17 and to what extent it delivers its generation to Idaho
18 Power's system. Consequently, Dynamis has an incentive to
19 make as many deliveries and make as much money as it can,
20 regardless of Idaho Power's need for that generation or the
21 cost of other available resources on Idaho Power's system
22 at the time the QF delivers its generation.
23 Q. Mr. Looper also states that "As far as other
24 renewable generators such as wind and solar, forecasting
25 tools have become more sophisticated and on-site weather
PARK, REB 4
Idaho Power Company
1 data combined with regional weather stations are being used
2 to monitor real time conditions." What is your response?
3 A. Mr. Looper is correct that the industry
4 continues to develop better forecasting tools to assist
5 with the ability to better anticipate when intermittent
6 resources will provide generation to Idaho Power's system.
7 The fact of the matter, however, is that it is still
8 impossible to predict with accuracy when the wind will
9 blow, and Idaho Power continues to experience volatility in
10 trying to determine when wind generation will provide
11 energy on its system. In addition, none of the QF wind
12 generators on Idaho Power's system provide generation
13 schedules to Idaho Power. And, even if they did, there are
14 no "teeth" in the power purchase agreements to enforce
15 those schedules. My understanding is that in the recent
16 agreements Idaho Power has entered into with QFs, the only
17 performance guarantees are a "Mechanical Availability
18 Guarantee," which only requires that the QFs' equipment be
19 mechanically available for a specific amount of time each
20 month. While I understand that as a policy matter there
21 are reasons for not requiring wind generators to provide
22 schedules, from a system planning and operating standpoint,
23 intermittent generators can cause significant issues with
24 reliably operating Idaho Power's system.
25
PARK, REB 5
Idaho Power Company
1
Q. Mr. Looper is also critical of how Idaho Power
2 characterizes "must run" resources and how it will treat
3 those resources in the implementation of Schedule 74. What
4 is your response?
5 A. Mr. Looper's characterization of how Idaho
6 Power will determine its "must run" resources under
7 Schedule 74 misstates what Idaho Power has said in
8 testimony and responses to discovery and is based on the
9 assumption that some sort of carbon tax currently exists.
10 Idaho Power operates its coal resources based upon load
11 need and market conditions. Typically, in the spring
12 months, Idaho Power will have two Bridger units dispatched
13 and its Valmy and Boardman units will either be off-line or
14 Idaho Power's partners at those facilities will be taking
15 Idaho Power's share of generation. From an operational
16 perspective, Idaho Power will dispatch those two Bridger
17 units such that they are backed-down to minimum loading
18 during the light load hours and ramped-up to meet the peak
19 or sell into the market, if it is economical and beneficial
20 to the Company's customers, during the heavy load hours.
21 Importantly, and as explained in my direct testimony, the
22 Company's coal generators cannot simply be "shut off" and
23 then turned back on to serve load. Once fired from a cold
24 start, it takes a coal plant several days to heat up in
25 order to reach generation levels. In addition, and as
PARK, REB 6
Idaho Power Company
1 explained in my direct testimony, cycling off coal units is
2 hard on the generators as changes in temperatures from hot
3 to cold and cold to hot on a frequent basis causes
4 excessive stress and fatigue on the turbines and other
5 equipment.
6
Q. Mr. Looper contends that if a hypothetical
7 carbon tax were to come to pass, it may be cheaper to
8 operate the Company's natural gas peaker plants than its
9 coal units. What is your response?
10 A. I do not want to speculate as to whether some
11 sort of federal carbon tax would make it less expensive to
12 run Idaho Power's natural gas peaking units versus Idaho
13 Power's coal generators. However, the reality is that,
14 currently, no carbon tax exists. If a carbon tax were to
15 be implemented, obviously, Idaho Power would need to
16 examine all of its resources to determine the impacts of
17 such a carbon tax on its system, including how it would
18 impact the implementation of Schedule 74. Since no carbon
19 tax currently exists and is not a real cost of operations,
20 it is not appropriate to treat it as such. Idaho Power
21 operates its own generation resources based upon real
22 economics, not hypothetical scenarios.
23
Q. Both Mr. Looper and the North Side Canal
24 Company's Donald Schoenbeck are critical of Idaho Power's
25 characterization in Schedule 74 of including Langley Gulch
PARK, REB 7
Idaho Power Company
1 power plant ("Langley Gulch") as a "must run" resource.
2 What is your response?
3 A. Langley Gulch is considere I a "must run"
4 resource to meet system peak demands and will also be "must
5 run" during periods of the year in which the Company needs
6 more flexibility in ramping to integrate the growing amount
7 of intermittent resources on Idaho Power's system.
8 Currently, Idaho Power relies, to a large extent, on the
9 ability of the Hells Canyon hydro facilities to integrate
10 intermittent generators on its system. Langley Gulch will
11 add more integration capability to Idaho Power's system
12 because of its ability to ramp up and down more quickly
13 than the Company's coal-fired generators. However,
14 although Langley Gulch has the ability to ramp up and down,
15 there are still limitations on taking it off-line during
16 low loading periods. To ensure its availability to ramp
17 when the variable intermittent resources drop or fall off,
18 Langley Gulch will need to be on-line and running at
19 minimum loadings during some periods, making it a "must
20 run" resource, in order to provide the regulation service
21 and other ancillary services required by North American
22 Electric Reliability Corporation mandatory reliability
23 standards.
24
25
PARK, REB 8
Idaho Power Company
1 II. OTHER ISSUES
2 Q. What is your response to the Direct Testimony
3 of Idaho Conservation League's Justin Hayes?
4 A. As an initial matter, I must say that I am not
5 qualified to speak on the various details of the Company's
6 FERC licensing requirements for its hydro generation
7 facilities. The Company has a separate team of individuals
8 that deal in the specialized area of administering its FERC
9 licenses. That said, as the Director of Load Serving
10 Operations, I am responsible for ensuring that the
11 Company's Grid Operations group maintains Idaho Power's
12 hydro generators in accordance with the information
13 provided by its FERC licensing team.
14 As for Mr. Hayes' testimony, I really find it quite
15 puzzling. His entire testimony focuses on responding to a
16 single sentence made at page 20 of my direct testimony.
17 Mr. Hayes' only issue appears to be increasing water flows
18 at four of Idaho Power's run-of-river hydro generating
19 facilities. Water flow and other water quality issues are
20 part of Idaho Power's obligations to meet applicable
21 provisions of the federal Clean Water Act, as prescribed in
22 the Company's FERC licenses. Thus, Mr. Hayes'
23 recommendations are, in general, beyond the scope of this
24 proceeding.
25
PARK, REB 9
Idaho Power Company
1 Q. At page 5 of the Direct Testimony of Ted
2 Sorenson for the Renewable Energy Coalition, Mr. Sorenson
3 describes how it is physically possible to ramp hydro
4 generation at facilities such as Idaho Power's run-of-river
5 hydros. What is your response?

6 A. Mr. Sorenson caveats his description of how it
7 is physically possible to ramp hydro generation by stating
8 he is not "getting into a discussion of legal issues
9 concerning what Idaho Power's FERC licenses may or may not
10 require . . . •" Idaho Power must operate its hydro system
11 in accordance with its FERC licenses. Thus, any
12 description of the operation of Idaho Power's hydro
13 generators without consideration of the Company's FERC
14 licenses, which Mr. Sorenson does, is meaningless.

15 Q. Mr. Sorenson and Mr. Hayes claim that the FERC
16 licensing for the Mid-Snake projects allows for
17 implementing spill instead of generating. What is your
18 response?
19 A. While it is true the Company has some limited
20 ability to spill at its Mid-Snake hydro facilities, Mr.
21 Sorenson and Mr. Hayes fail to understand the operational
22 restrictions that are a portion of the FERC licenses
23 associated with those facilities. In order for the Milner,
24 Twin Falls, Bliss, and Lower Salmon Falls plants to pass
25 river requirements via spill instead of generation, Idaho
PARK, REB 10
Idaho Power Company
1 Power grid operators must do so at each generating plant
2 while maintaining the FERC license requirements. Even if
3 this could be done without violating the requirements of
4 the FERC licensing, this is not an easy task nor is it one
5 that can be done quickly. It becomes even more complicated
6 when an over generation event occurs, such as high hydro
7 conditions and maximum wind generation on Idaho Power's
8 system. For example, take a situation where wind ramps up
9 by 300 megawatts ("MW") and then backs down by 250 MW
10 within a one hour time frame, which is a very realistic
11 scenario on Idaho Power's system. In this case, the Idaho
12 Power generation dispatcher would need to go through the
13 timely process of carefully ramping the generation down
14 incrementally at each Mid-Snake plant, while ensuring that
15 FERC licensing criteria are not violated, as the wind
16 increased within the hour while opening the spill gates.
17 Importantly, this process is not responsive enough to
18 ensure the Company maintains its mandatory system
19 reliability parameters. Moreover, the generation
20 dispatcher is also tasked with operating the remaining
21 plants on the Company's system and responding to lost
22 generation and load variations which may be caused by a
23 variety of factors.
24 Q. The Direct Testimony of Dr. Don Reading
25 suggests that from a transmission and interconnection cost
PARK, REB 11
Idaho Power Company
1 perspective, the Idaho Public Utilities Commission should
2 implement a policy that treats QF generators the same as
3 utility-owned resources and other non-PURPA generators,
4 where the utility is able to fully recover such
5 transmission and interconnection costs from its customers
6 and that non-utility, non-PURPA generators receive a refund
7 over time for the entire cost of transmission system
8 upgrades. What is your response?
9 A. I disagree that QFs should be allowed to
10 recover interconnection and transmission costs associated
11 with QF projects. Utility-owned resources are part of a
12 thorough, integrated resource planning process which also
13 must go through a contested regulatory proceeding to
14 receive a Certificate of Public Convenience and Necessity.
15 In addition, when siting utility-owned resources, the
16 Company looks at proximity of the resource to loads and/or
17 available transmission capacity. PURPA generators, on the
18 other hand, locate their generation projects without any
19 regard or consideration for Idaho Power's system needs,
20 proximity to loads, or available transmission capacity.
21 Idaho Power's customers must be held indifferent to the
22 transactions required by the QF. But for the QF
23 generator's request, the utility would not build the
24 interconnection and transmission facilities that are
25 required to connect the QF generator to the system and
PARK, REB 12
Idaho Power Company
1 bring its generation to Idaho Power loads. As a result of
2 the large amount of PURPA requests on Idaho Power's system,
3 the Company has to complete interconnection and
4 transmission system upgrades that it otherwise would not
5 need to serve load. Because these system upgrades do not
6 serve any other purpose or need required to provide service
7 to Idaho Power's customers, it would not be appropriate to
8 require customers to pay for interconnection and
9 transmission system upgrades that are not needed to serve
10 load.
11 Q. Mr. Looper's testimony discusses the March
12 2012 Bonneville Power Administration's ("BPA") Dispatch
13 Standing Orders wherein BPA proposes to compensate wind
14 generators on its system that it curtails due to generation
15 oversupply events. Mr. Looper alleges this is BPA's "own
16 version of Schedule 74." Do you agree that BPA's proposal
17 is similar to Idaho Power's proposed Schedule 74?
18 A. Absolutely not. Idaho Power's situation is
19 completely different than BPA's. The vast majority of the
20 wind generation on Idaho Power's system is QF generation
21 that Idaho Power has a "must purchase" obligation under
22 PURPA and which Idaho Power must use to serve load. The
23 wind generation on BPA's system is not being purchased by
24 BPA but consists of point-to-point transmission service
25 that BPA simply wheels, or transmits, for the generator,
PARK, REB 13
Idaho Power Company
1 and does not use the generation to serve its customers.
2 Thus, BPA is proposing to curtail an oversupply of
3 generation in its balancing area when it cannot export
4 generation to other balancing areas - to curtail generation
5 during oversupply periods from a transmission provider's
6 perspective. Idaho Power's proposed Schedule 74 proposes
7 to operationally dispatch QF generators so as to
8 efficiently manage load services and load serving
9 operations on its system. Specifically, Idaho Power's
10 Schedule 74 is uniquely designed to effectuate FERC PURPA
11 regulations, namely 18 C.F.R. § 292.304(f), which relieves
12 Idaho Power from its obligation to purchase QF generation
13 during light loading periods, when only base load units are
14 operating and Idaho Power would be forced to cut back
15 output from the units in order to accommodate the
16 unscheduled QF energy purchases. Because such base load
17 units might not be able to later increase their output
18 levels rapidly when the system demand later increased,
19 resulting in the utility needing to rely upon less
20 efficient, higher cost units, FERC has stated that C.F.R. §
21 292.304(f) applies to such low loading situations and can
22 be used by utilities to curtail QF generation in such
23 instances. In sum, Idaho Power and BPA are in completely
24 different situations and it is not appropriate to draw
25
PARK, REB 14
Idaho Power Company
1 comparisons between what BPA is proposing and what Idaho
2 Power is proposing.
3 Q. Does this conclude your rebuttal testimony?
4 A. Yes.
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PARK, REB 15
Idaho Power Company
CERTIFICATE OF SERVICE
I HEREBY CERTIFY that on the 29th day of June 2012 I served a true and
correct copy of the REBUTTAL TESTIMONY OF TESSIA PARK upon the following
named parties by the method indicated below:
Commission Staff
Donald L. Howell, II
Kristine A. Sasser
Deputy Attorneys General
Idaho Public Utilities Commission
472 West Washington (83702)
P.O. Box 83720
Boise, Idaho 83720-0074
Avista Corporation
Michael G. Andrea
Avista Corporation
1411 East Mission Avenue, MSC-23
P.O. Box 3727
Spokane, Washington 99220-3727
PaciflCorp dlbla Rocky Mountain Power
Daniel E. Solander
PacifiCorp d/b/a Rocky Mountain Power
201 South Main Street, Suite 2300
Salt Lake City, Utah 84111
Exergy Development, Grand View Solar II,
J.R. Simplot, Northwest and Intermountain
Power Producers Coalition, Board of
Commissioners of Adams County, Idaho,
and Clearwater Paper Corporation
Peter J. Richardson
Gregory M. Adams
RICHARDSON & O'LEARY, PLLC
515 North 27th Street (83702)
P.O. Box 7218
Boise, Idaho 83707
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Ben Johnson Associates, Inc.
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Grand View Solar II
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North Side Canal Company
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Birch Power Company
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