20120131Park Direct.pdf

RECEIVED
2012 JAN 31 PH 3: 22
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-II-03
IDAHO POWER COMPANY
DIRECT TESTIMONY
OF
TESSIA PARK
i 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.By whom are you employed and in what capacity?
5 A.I am employed by Idaho Power Company ("Idaho
6 Power" or "Company") as the Director of Load Serving
7 Operations. In that role, I am responsible for the Grid
8 Operations and Balancing Operations functions for the
9 Company's electric system.
10 Q.Please describe your educational background
11 and work experience with Idaho Power.
12 A.I have been employed with the Company for 14
13 years in the Operations area. I worked in the Grid
14 Operations department as a Grid Operator, Grid Operator
15 Training Leader, and the Interchange Operations Leader. I
16 worked as the Grid Operations Manager from 2007 to June
17 2009 and then the Power Supply Operations Manager from June
18 2009 through 2010 where I assumed my current role. I have
19 attended Boise State University and am currently in my
20 final year of studies in the BAS Energy Management program
21 at Bismark State College.
22 Q.What is the purpose of your testimony in this
23 matter?
24 A.The purpose of my testimony is to describe the
25 economic and operational impacts resulting from the
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Idaho Power Company
1 uneconomic dispatch of Idaho Power base load resources
2 caused by the mandatory obligation to purchase generation
3 from qualifying facilities ("QFs") pursuant to the Public
4 Utility Regulatory Policies Act of 1 97 8 (" PURPA") that, in
5 many instances, are not needed to serve the Company's
6 system load. I will also describe constraints around the
7 Company's ability to move energy to market during times of
8 excess supply, as well as describe how there is a finite
9 amount of intermittent generation that is capable of being
10 integrated onto the Company's system. Further, I will
11 describe the Company's proposed operational re-dispatch
12 rule and proposed tariff schedule that considers system
13 operational circumstances and dispatching of the Company's
14 generation resources in the most efficient manner versus
15 dispatching less efficient and more expensive resources so
16 as to be able to accommodate additional PURPA generation
17 resources onto the Company's system.
18 I . CURNT SYSTEM OPERATION
19 Q.Please provide an overview of the amount of QF
20 generation currently on the Company's system.
21 A.As explained in the Direct Testimony of M.
22 Mark Stokes, as of December 31, 2011, Idaho Power had 119
23 QF projects under contract with an estimated nameplate
24 rating of 989 megawatts ("MW"). Of these projects, 96 (606
25
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Idaho Power Company
1 MW) are currently on-line, and an additional 23 proj ects
2 (383 MW) are scheduled to come on-line by early 2014.
3 Q.From an operations standpoint, do you have
4 concerns with the amount of QF generation that has been
5 added to the Company's system?
6 A.Yes. The Company is now in the position
7 where, at certain times of the year, it has to back-down
8 base load generation in order to integrate PURPA generation
9 which is predominantly intermittent in nature. When base
10 load generation is backed down, it can become difficult to
11 ramp up (or ramp down) that generation to meet variations
12 in system needs, especially when the Company has to reserve
13 a portion of its base load generation to ensure it can firm
14 and shape the intermittent PURPA generation for reliability
15 reasons. Put differently, the addition of PURPA resources
16 to the Company's system frequently requires the Company to
17 have partially loaded resources running and on-line in
18 order to meet the variability of intermittent resources.
19 Q.From an operations standpoint, how is
20 intermittent generation, such as wind, different from
21 traditional base load generation resources?
22 A.The big difference is the ability, or more
23 appropriately, the inability to schedule and dispatch
24 intermittent generators. Unlike traditional hydro and
25 thermal resources , intermittent resources like wind cannot
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Idaho Power Company
1 be scheduled. While the Company and the industry are
2 continuing to develop more robust forecasting tools , it is
3 still difficult to predict with any accuracy when the wind
4 will blow and thus when wind turbines will generate energy.
5 In other words, the Company has no way of controlling how
6 much of this type of energy it will get or when it will get
7 it . Moreover, the Company is currently required to absorb
8 this QF energy onto its system without regard to its
9 electrical system needs. This is especially problematic in
10 low loading periods, i.e., when the Company schedules its
11 near-term load and reliability forecasts and sets
12 generation levels at its base load units accordingly.
13 During these times, the amount of total generation on the
14 Company's system (as a result of the surplus of QF energy
15 at certain times) can exceed Idaho Power' s ability to back
16 down additional, base load resources. When this occurs,
17 this leaves the Company with only limited dispatchable
18 generation available for load ramping events (i. e., changes
19 in load or levels of intermittent generation.)
20 Q.Doesn't the Company have the ability to sell
21 excess energy on its system into the market?
22 A.Generally, yes . Given certain meteorological
23 conditions and based upon its generation resources, the
24 Company generally knows that there will be many times in
25 the year when its generation will exceed its system load.
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Idaho Power Company
1 Transactions selling such surplus energy can be established
2 at varying intervals prior to the actual period of energy
3 surplus. For example, Idaho Power frequently recognizes
4 periods of surplus energy months in advance through the
5 long-term operations planning cycles as part of its Risk
6 Management Policy. Conversely, energy surpluses are, at
7 times, recognized during real-time operations, within only
8 several hours of the actual surplus condition.
9 Q.Are there Federal Energy Regulatory Commission
10 ("FERC") regulations that govern how the Company has to
1 1 sell energy into the market?
12 A.Yes. FERC Order No. 890 placed restrictions
13 on the Company's ability to sell power from utility-owned
14 generation resources. Regardless of the interval at which
15 the surplus is recognized and transacted, the actual real-
16 time delivery of power to the acquiring third-party is
17 managed in practice through the undesignation of network
18 resources, thereby releasing these resources from their
19 designation for serving network customer demand, and
20 assigning at least a portion of their production in support
21 of off-system sales. More specifically, when an
22 interconnecting resource connects to Idaho Power's system
23 as a designated network resource, that resource can only be
24 used to serve system load unless the Company specifically
25 undesignates that resource through a process that is
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Idaho Power Company
1 noticed on the Company's Open-Access Same-Time Frame
2 Information System ("OASIS") web site, which is managed by
3 the Company's transmission provider function. Once
4 undesignated, the network resources assigned in support of
5 off-system sales are effectively committed for this
6 purpose, and, as such, are necessarily resources having
7 generating capacity which is delivered with very high
8 dependability. Idaho Power's practice is to undesignate
9 generation provided from its fleet of hydro and thermal
10 resources, as these resources have the type of demonstrated
11 dependability over years of operation that is required.
12 Q.How much energy can Idaho Power make available
13 to sell into the market?
14 A.The amount of Idaho Power's hydro and thermal
15 generating capacity which can be undesignated for service
16 to network demand and instead assigned in support of off-
17 system sales is recognizably finite. During periods of
18 relatively high customer demand, energy surpluses that
19 occur are typically small enough to consume only a fraction
20 of the finite generating capacity which can be
21 undesignated. Variable generation from intermittent PURPA
22 resources occurring during these periods can fulfill its
23 purpose of serving network demand, thereby allowing the
24 Company-operated hydro and thermal generators to expand
25 their commitment in support of off-system sales. Thus, the
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Idaho Power Company
1 limiting conditions on the amount of variable generation
2 from PURPA resources which Idaho Power can accommodate are
3 not apparent during periods of relatively high customer
4 demand.
5 However, during periods of low customer demand,
6 energy surpluses are frequently very large, consuming much
7 of the finite generating capacity which can be assigned in
8 support of off-system sales. Thus, as variable generation
9 from PURPA resources increases in service to network
10 demand, the Company-operated generators can expand their
11 off-system commitment by only a limited amount. Variable
12 generation occurring beyond this amount has no further
13 network customer demand to serve, and consequently cannot
14 be integrated without violating FERC requirements on
15 designated network resources and their service in meeting
16 network customer demand.
17 Q.Do the FERC rules related to designation and
18 undesignation impact the total amount of intermittent
19 generation the Company is capable of integrating onto its
20 system?
21 A.Yes. Gi ven the current network resource
22 stack, as well as the capabilities of the Company's
23 transmission system, there is only a finite amount of
24 intermittent generation the Company can add to its system.
25 As part of the Company's ongoing wind integration study,
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Idaho Power Company
1 Idaho Power is continuing to evaluate just how much that
2 is. While the Company is unable to precisely say how much
3 intermittent generation its system can absorb at this time,
4 gi ven the recent proliferation of intermittent generation
5 on its system and the amount that is scheduled to come on-
6 line, the Company believes it is quickly approaching that
7 maximum intermittent generation saturation point. Once
8 reached, the only way the Company will be able to add more
9 intermi ttent generation will be to build or configure
10 additional generation resources designed specifically to
11 provide the regulating margin needed to integrate these
12 variable resources. At this time, the Company has no plans
13 to add or configure additional generation resources to
14 provide regulating margin.
15 Q.What is the Company's experience with the
16 intermittent PURPA generators on its system?
17 A.As indicated above, the Company receives no
18 schedule for these generation resources, so it only has a
19 limited amount of information available as to when or how
20 much intermittent generation it is going to receive on any
21 given day. Often times, wind generators, the bulk of QF
22 generators on Idaho Power's system, generate during the
23 Company's low loading periods (e.g., at night, during the
24 spring or fall, etc.)During these low loading periods,
25 there is generally a glut of energy available in the
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Idaho Power Company
1 Pacific Northwest. In fact, over the last couple of years,
2 the Company has seen a phenomenon where market prices at
3 the Mid Columbia trading hub actually go negative, meaning
4 one entity will pay another entity to take their excess
5 energy. If the market price for energy is not negative
6 during these low loading periods , it is often times less
7 than the dispatch cost of the Company's thermal resources.
8 Thus, if the Company were to sell the energy produced by
9 its coal plants into the market, it would be doing so at a
10 loss. Moreover, the Company is limited in its ability to
11 market and sell its base load energy displaced by PUPRA
12 contract energy because of the undesignation issues
13 discussed earlier and because such sales are made on the
14 "spot market."Addi tionally, transmission constraints on
15 the Company's system may limit the amount of energy that
16 can be moved to market at a given time. Again, because
17 Idaho Power does not know when or how much energy it will
18 get from wind generators, it often times will not know if
19 it will have energy available to sell until the day, or
20 most often, an hour ahead of when it is sold. Thus, it is
21 not possible for the Company to enter into forward-looking,
22 long-term energy transactions to sell excess wind
23 generation into the market because there is no guarantee in
24 the future if the energy produced by wind generators will
25 be available.
PARK, DI 9
Idaho Power Company
1 Q.Can the Company undesignate its PURPA network
2 resources and sell that generation into the market?
3 A.Yes, but for the reasons described above, it
4 is difficult to do, primarily because the Company has no
5 abili ty to know with certainty whether generation from
6 intermittent PURPA resources will actually be generated.
7 In addition, if Idaho Power were to undesignate a PURPA
8 resource on its system and sell it into the market, and a
9 system condition requiring that sale to be curtailed
10 occurred, the Company would not be able to curtail the
11 PURPA generator because Idaho Power has no ability to
12 curtail PURPA generation for this purpose. In comparison,
13 when Idaho Power undesignates its base load or other
14 generation resources for sale into the market, and a system
15 condition occurs requiring that sale to be curtailed, the
16 Company curtails its generation resources. This example
17 highlights how even though PURPA resources are designated
18 as network resources, the Company has to give them special
19 treatment over how the Company treats its own generation
20 resources.
21 Q.How does the Company decide whether to
22 dispatch its resources to serve load or to sell into the
23 market?
24 A.Primarily, the Company bases its dispatch
25 decisions upon costs. It is prudent and standard electric
PARK, DI 10
Idaho Power Company
1 utility practice to dispatch available, existing resources
2 to meet system load beginning with the least expensive
3 resource. For example, the Company's least cost resources
4 to dispatch are its hydro resources. Because these
5 resources use water as fuel, there is effectively no
6 incremental cost associated with running these resources.
7 Thus, their dispatch cost is very low. The next least-cost
8 resources are the coal generators whose current dispatch
9 costs are generally below $30 per megawatt-hour ("MWh").
10 These dispatch costs are driven largely by fuel costs
11 (i.e., coal costs) for each facility. Once on-line, Langley
12 Gulch, a natural-gas-fired combined cycle combustion
13 turbine, will have dispatch costs that are heavily
14 influenced by the price of natural gas. Based upon the
15 current price of natural gas, dispatch costs of Langley
16 Gulch will be approximately $22.
17 Q.What are the dispatch costs of the PURPA
18 resources on your system?
19 A.Stating that the Company's PURPA resources
20 have dispatch costs is something of a misnomer because they
21 are, generally, not dispatchable. Instead, they connect to
22 the system and the Company takes whatever generation they
23 produce. The amount Idaho Power pays for PURPA generation
24 in comparison to the dispatch costs of Company-owned
25 resources is generally much higher. For example, the
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Idaho Power Company
1 Company currently pays in the range of low-$50 per MWh up
2 to $85 or more per MWh for PURPA generation.
3 Q.How does the Company use its resources to meet
4 system load?
5 A.Historically, Idaho Power has been able to
6 rely on its low cost hydro system to meet the broad
7 fluctuations in system load that can occur during a single
8 day. For example, on a given October day, the Company's
9 load may be 1,250 MW at 6 a.m., grow to 1,600 MW by 10
10 a.m., drop to 1,400 MW by 3 p.m. and drop again to 1,300 MW
11 by 11 p.m. Because Idaho Power's hydro system can, within
12 environmental limitations, be dispatched "on demand," it is
13 an ideal resource for meeting these daily fluctuations in
14 load.
15 Q.How has the addition of large amounts of PURPA
16 generation affected the way Idaho Power operates its
17 system?
18 A.The addition of large amounts of intermittent
19 generation on the system, coupled with the fact that it
20 oftentimes generates when the Company's system load is at a
21 low level, forces the Company to use the flexibility of the
22 hydro system that is normally used to meet load swings and
23 to meet system balancing needs (e. g., regulation reserves,
24 contingency reserves, etc.) of the wind generators. Thus,
25 the Company is forced to use base load generation resources
PARK, DI 12
Idaho Power Company
1 to integrate the intermittent QF generation which comes at
2 an additional cost to customers.
3 Q.Doesn't the Company's current $ 6.50 wind
4 integration charge cover the cost of providing these
5 balancing services to intermittent generators, such as wind
6 generators, on your system?
7 A.Partially. As an initial matter, it is
8 important to point out that the $ 6.50 wind integration
9 charge was the result of a negotiated settlement and is not
10 reflective of the Company's actual integration costs. The
11 $ 6.50 wind integration charge included in the settlement
12 stipulation was intended to cover the lost opportunity cost
13 of having to de-optimize the operation of the Company's
14 hydroelectric resources in the Hells Canyon Complex in
15 order to provide the reserve capacity necessary to respond
16 to changes in wind generation. In the October 2007
17 addendum to Idaho Power's initial wind integration study,
18 an additional 48 MW of down regulating capability was also
19 assumed to be available from the Jim Bridger coal plant.
20 This assumption and the resulting impact to the wind
21 integration cost did not account for potential costs due to
22 thermal cycling.
23 Q.Is Idaho Power currently updating its wind
24 integration study?
25
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Idaho Power Company
1 A.Yes. Idaho Power has been working on an
2 update to its wind integration study for some time.
3 However, difficulties in modeling Idaho Power's electrical
4 system and generation resources in the model used by the
5 consultant hired to perform the study, have delayed the
6 completion of the study. The Company is currently working
7 through the i~sues with the consultant and hopes to have
8 the study completed by this summer.
9 Q.Can you summarize what all of this means from
10 an operational perspective?
11 A.In short, the recent influx of QF generation
12 onto the Company's system is requiring the Company to
13 displace lower cost, dispatchable generation resources with
14 higher cost, non-dispatchable, intermittent resources.
15 Simply put, for customers, this means they are paying more
16 for less reliable generation resources.
17 II. 18 C.F.R. § 292.304(£)
18 Q.Do FERC's PURPA regulations have a provision
19 that allows utilities to consider the economic and
20 operational impacts of PURPA generators?
21 A.Yes. FERC regulations implementing PURPA
22 contain a provision which deals with this issue.
23 Subsection 292.304 (f) of Title 18 of the Code of Federal
24 Regulations describes situations whereby utili ties are not
25 required to purchase electric energy or capacity during any
PARK, DI 14
Idaho Power Company
1 period which, due to operational circumstances, purchases
2 from QFs will result in costs greater than those which the
3 utility would incur if it did not make such purchases, but
4 instead generated an equivalent amount of energy itself.
5 In other words, this regulation allows the Company to
6 curtail QF generators on its system under certain
7 operational and economic circumstances.
8 Q.Is this regulation applicable to the situation
9 Idaho Power is currently in?
10 A.Absolutely. This FERC regulation refers to
11 the situation that Idaho Power is currently experiencing
12 during the Company's low loading periods. As described
13 above, there are times when the Company is faced with
14 displacing lower cost, base load generation resources with
15 higher cost resources to serve system load.
16 Q.Doesn't the Company's Schedule 72 tariff and
17 existing firm energy sales agreements ("FESA") with QFs
18 give the Company the ability to curtail QF generation?
19 A.Yes, but not for reasons that have anything to
20 do with system efficiency and economics. Schedule 72 and
21 the FESA's give the Company the ability to curtail due to
22 system integrity issues. The FERC rule I cite above allows
23 the Company to limit the obligation to purchase QF energy
24 if the Company is operating only base load units and would
25 be forced to cut back output from those units in order to
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Idaho Power Company
1 accommodate QF energy purchases. Such base load units
2 might not be able to later increase their output levels
3 rapidly enough to meet system demand, resulting in the
4 Company needing to rely upon less efficient and/or higher
5 cost resources to meet system load.
6 Q.Does the FERC rule you cite above only
7 consider economics?
8 A.No. The FERC rule requires that economics are
9 to be considered only during certain "operational
10 circumstances." My understanding of this is that
11 curtailment of QF's under the FERC rule applies only to
12 such low loading scenarios (as I describe in greater detail
13 later) and cannot be relied upon to curtail purchases of QF
14 energy for general economic reasons only.
15 Q.Are you aware of any state utility commissions
16 that have implemented the FERC rule you mention above?
17 A.Yes. I know of at least two states that have
18 addressed and/or implemented this FERC rule: Florida and
19 Nevada.
20 Q.Please briefly describe your understanding of
21 the situation in Florida.
22 A.It is my understanding that in the mid 1990s,
23 Florida Power Corporation ("FPC") was experiencing
24 operational circumstances during certain low loading
25 periods wherein the purchase of QF energy in lieu of taking
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Idaho Power Company
1 energy the utility could generate itself resulted in
2 negative avoided costs, meaning that purchases from QFs
3 caused FPC to incur greater net power production costs than
4 it would otherwise incur without those purchases. As a
5 result, the Florida Public Service Commission (" Florida
6 PSC") adopted a rule nearly identical to 18 C. F. R. §
7 392.204 (f) and implemented it in such a way that allowed
8 FPC, during certain low loading conditions, to not have to
9 make purchases of QF energy at negative avoided costs and,
10 instead, curtail QF energy for periods of time.
11 Q.Please explain your understanding of how the
12 FERC regulation was implemented in Nevada.
13 A.My understanding of what occurred in Nevada is
14 that the Nevada Public Service Commission ("Nevada PSC") in
15 the mid-1990s adopted a specific "Policy and Procedure of
16 Curtailment of Certain PURPA Qualifying Facilities" that
17 was proposed by Nevada Power Company. That policy was
18 adopted and implemented as a direct result of the authority
19 given to the Nevada PSC by the FERC rule. I have attached
20 a copy of the policy adopted by the Nevada PSC as Exhibit
21 No.4.
22 Q.Has FERC given any direction as to how this
23 rule is to be implemented?
24 A.Yes. In a very recent order, FERC confirmed
25 that while 18 C.F.R. § 292.304 (f) does not give utilities
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Idaho Power Company
1 blanket authorization to curtail QF purchases for economic
2 reasons, during low loading periods, utili ties may curtail
3 higher cost QF energy if the utility would have to dispatch
4 less efficient, higher cost units (other than base load
5 units) to meet system load. Entergy Services, Inc., 137
6 FERC P 61199, 2011 WL 6523725 (F.E.R.C.), Docket Nos. ER05-
7 1065-011, OA07-32-00S (Dec. 15, 2011) ("Entergy Order") .
S III. IDAHO POWER'S OPERATIONAL DISPATCH PROPOSAL
9 Q. What specifically is Idaho Power proposing?
10 A. The Company is proposing an operational
11 dispatch model that allows the Company, during low loading
12 periods, to meet its energy needs by using its own lowest
13 cost, base load resources instead of dispatching less
14 efficient, higher cost resources to accommodate PURPA
15 generators on the Company's system. Attached as Exhibit
16 No. 5 is a copy of the Company's proposed Tariff Schedule
17 74 describing the proposal.
lS Q.Please provide a brief overview of the
19 Company's proposal.
20 A.In adhering to the FERC rule, the Company's
21 proposal will relieve the Company of its obligation to
22 purchase energy from PURPA generators during low loading
23 periods when the Company is operating only base load
24 resources and would be forced to cut back output from those
25 resources in order to accommodate unscheduled QF energy
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Idaho Power Company
1 purchases. Because the Company's coal units have slow,
2 gradual ramp times for them to reach full generating
3 capacity, backing down such base load units too much to
4 accommodate QF purchases will impact their ability to come
5 back to full generating capacity to meet system load. If
i
6 this were to occur, Idaho Power would be in the position of
7 dispatching higher cost resources, such as the Company's
8 natural gas peaking plants or more expensive market
9 purchases, to meet variations in system load. This is
10 exactly the type of scenario under which the FERC rule was
11 meant to apply and why Idaho Power is requesting authority
12 from the Commission to implement it.
13 Q.Describe how you determined the Company's "low
14 loading periods."
15 A.The Company looked at its hourly energy needs
16 throughout the entire year. Generally, during most months
17 out of the year, the Company has more generation resources
18 than it has load primarily because the Company's summer
19 peak is significantly higher than its winter peak. During
20 these times of excess generation capacity, the Company
21 either backs down or shuts down its more expensive
22 generation resources, or, if the dispatch costs of those
23 resources are less than the market price, the Company will
24 generate energy and sell it into the market. Any profit
25 the Company makes in doing this flows back to customers as
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Idaho Power Company
1 a benefit through the Company's power cost adj ustment
2 ("PCA") mechanism. During the months of the year when the
3 Company does not have enough generation to meet its loads,
4 the Company uses its peaking generation resources, as well
5 as market purchases to meet its system load needs. To
6 determine the Company's low loading periods, the Company
7 looked at those times of the year when system loads are
8 less than the Company's "must run" resources. "Must run"
9 resources consist of three types:(1) those generation
10 resources the Company must have available to serve near-
11 term forecasted load, (2) run-of-river hydro generators,
12 and (3) hydro generation needed to maintain the required
13 flows for environmental compliance. Pursuant to the FERC
14 licenses Idaho Power has for its run-of-ri ver hydro
15 electric proj ects, the Company is obligated to take
16 whatever generation flows through them; it does not have
17 the ability to decrease or increase the generation. Thus,
18 the output of those resources depends upon water
19 condi tions. It can be difficult to define in advance those
20 resources that are needed to reliably serve loads in future
21 hours. For example, run-of-river hydro and minimum flow
22 hydro generation varies depending upon water flows and the
23 time of year. In addition, meteorological conditions
24 (e. g., unseasonably warm or cold temperatures or unusually
25 dry or wet moisture levels, etc.) as well as other factors
PARK, DI 20
Idaho Power Company
1 that impact system load may dictate which resources are
2 considered "must run." In general, however, the Company
3 relies on thermal resources to meet base load requirements,
4 and use the flexibility of hydro resources to meet
5 variations in load throughout the day. The "must run"
6 periods are those periods when the load demand in the
7 upcoming hours or days requires the base load thermal
8 resources to be available to serve load (and assuming the
9 dispatch costs of thermal resources are less than market
10 prices during heavy load hours). This means the Company
11 must have its thermal plants generating and on-line and
12 capable of ramping up during heavy load hours and then
13 backing down again during light load hours.
14 Q.Why doesn't the Company simply shut off its
15 thermal units during the light load hours during these low
16 loading periods?
17 A. The coal units cannot be shut off for two
18 reasons. First, operationally, coal plants cannot be
19 simply shut off. Once fired, it takes a coal plant several
20 days to heat up in order to reach generation levels. In
21 addition, cycling off coal plants is very hard on the
22 generators as changes in temperatures from hot to cold and
23 cold to hot on a frequent basis causes excessive stress and
24 fatigue on the turbines and other equipment. Second, Idaho
25 Power is only part owner of all three of the coal plants
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Idaho Power Company
1 and is not the operator of any of them. Under the
2 Company's contracts with the other co-owners and operators,
3 if the Company requests that a coal generator be taken off-
4 line, the Company is required to give seven days prior
5 notice prior to restarting it and may incur additional
6 charges from the operators for doing so.
7 Q.When will the Company's low loading periods
8 occur?
9 A.While it is impossible to predict exactly when
10 the Company's low loading periods will occur for the
11 reasons that I have outlined earlier in my testimony, the
12 Company anticipates that the low loading periods will occur
13 predominantly in the spring and fall when temperatures are
14 mild and no market exists for excess energy. The Company's
15 system load will be such that it needs to have thermal
16 units on-line to provide some energy during light load
17 hours so they can again provide energy during heavy load
18 hours. Over the last few years, it has been the Company's
19 observation that the intermittent PURPA generation
20 interconnected to the system generally provides a lot of
21 energy at night and during the spring and fall, the times
22 when the system is experiencing low loads. Thus, low
23 loading periods will likely occur during the night and
24 during the "shoulder months" of spring and fall.
25
PARK, DI 22
Idaho Power Company
1 Q.Can you provide a representative example of
2 when your proposed Schedule 74 Tariff would go into effect?
3 A.Yes. The following example is based upon an
4 actual generation day in October 2011. On a typical fall
5 day, the Company's load may swing between approximately
6 1,100 MW during light load hours and 1,600 MW during heavy
7 load hours.During the light load hours, the Company must
8 maintain constant minimum flows below Hells Canyon dam for
9 environmental compliance, thus limiting the ability to
10 curtail generation out of the Hells Canyon Complex to no
11 less than approximately 350 MW.During the fall, the
12 Company has relatively low, steady flows at the run-of-
13 ri ver hydro plants, providing a constant, steady flow of
14 approximately 450 MW of energy. The Company will schedule
15 these hydro resources to serve load. Thermal units that
16 are "in the money"! are on-line, which are capable of
17 providing us up to 600 MW. The Company will schedule all
18 of these resources to serve load. The Company has up to
19 395 MW of intermittent PURPA wind generation interconnected
20 to the system, none of which can be scheduled.In
21 addition, the Company has another 50 MW of firm PURPA
i In this context, "in the money" simply means that Company-owned
generation resources would be less expensive than market prices. Under
this scenario, the Valmy plant would be cycled off for an extended
period of time because of its relatively high dispatch cost and because
it is not needed to serve load during these low load times of year.
PARK, DI 23
Idaho Power Company
1 generation (e. g., non-intermittent generation resources
2 such as digesters and hydros) that is scheduled.
3 Assume that between midnight and 4 a .m. load is
4 relatively steady at 1,100 MW. The Company has its thermal
5 units backed down and running at 300 MW, and its hydro
6 plants running at a minimum of 817 MW (350 MW from Hells
7 Canyon and 447 MW from the run-of-river hydro). The
8 Company has the additional 50 MW of non-intermittent PURPA
9 on-line and providing energy. Added together, these
10 resources are sufficient to serve the 1,100 MW of light
11 load. Importantly, the Company needs to keep its thermal
12 units running at least at 300 MW so they will be able to
13 ramp up to their full output of 600 MW to serve load during
14 the heavy load hours. If during the hours between midnight
15 and 4 a.m. the Company has 300 MW of unscheduled PURPA wind
16 generation come onto its system, it has to back down other
17 generation so as to balance generation and load across its
18 system. Because Idaho Power cannot back down its hydro
19 units, nor can it back down the thermal units below 300 MW,
20 the Company would curtail the PURPA generation during these
21 hours to balance generation with load. If Idaho Power were
22 to cycle off its thermal units in the middle of the night
23 to accommodate this PURPA generation, the Company would
24 need to start up its higher cost, less efficient natural
25 gas peaking units or make more expensive market purchases
PARK, DI 24
Idaho Power Company
1 (assuring transmission would be available) to meet system
2 load during heavy load hours during the next day.
3 iv. CURTAILMNT PROCEDUR
4 Q.On what basis does the Company propose to
5 curtail the excess PURPA generation during these low
6 loading periods?
7 A.During the "must run" periods, the Company
8 will curtail all PURPA resources to which this procedure
9 applies on a pro rata basis until there is no longer excess
10 energy on the Company's system.
11 Q~Will the Company notify the QF generators when
12 it is going to limit energy purchases from them?
13 A.Absolutely. In fact, the FERC regulations
14 require the Company to provide notice to QFs prior to
15 curtailing them under C. F. R. § 292.304 (f). Idaho Power
16 will provide QFs notice on both a day-ahead basis based
17 upon forecasts and also provide them real-time notice if
18 the need to curtail changes.
19 Q.Is the Company proposing to implement this
20 policy to only new PURPA contracts or to all current and
21 new PURPA contracts?
22 A.The Company is proposing to apply this policy
23 to all PURPA contracts, both existing and new, that are
24 proj ects which contain generator output control limiters
25 ("GOCLs") and are 10 MW or larger in size.
PARK, DI 25
Idaho Power Company
1 Q.Why is the Company suggesting these
2 parameters?
3 A.The Company set these parameters based upon
4 practical considerations. Large, intermittent QF
5 generators interconnected to Idaho Power's system have
6 GOLCs which give the Company the ability to limit QF
7 generation on a real -time basis. Correspondingly, the same
8 devices allow the Company to re-integrate these large QF
9 generators' full output onto the Company's system on a
10 real-time basis once the light loading periods have passed.
11 Smaller and older QF generators on the Company's system do
12 not have this technology. In many instances, such
13 technology could be installed, but it would be very
14 expensive and not economically feasible for small QF
15 proj ects. In addition, these smaller QF proj ects generally
16 contribute only small amounts of energy to the Company's
17 system, and curtailing such proj ects by themselves would
18 not likely impact the excessive energy the Company has on
1 9 its system during light loading periods.
20 Q.Does this conclude your direct testimony?
21 A.Yes.
22
23
24
25
PARK, DI 26
Idaho Power Company
BEFORE THE
IDAHO PUBLIC UTiliTIES COMMISSION
CASE NO. GNR-E-11-03
IDAHO POWER COMPANY
PARK, 01
TESTIMONY
EXHIBIT NO.4
Power Co. v. Nevada Power 1994 WL 780897
POLICY AND PROCEDURE FOR CURTAILMENT OF CERTAIN PURA QUALIFYING FACILITIES
I. APPLICABILITY: This policy and procedure shall govern curtilments by Nevada Power Company ('NPC') of the capacity
and energy which may be made available by Saguaro Power Company, Nevada Cogeneration Associates 1, and Nevada
Cogeneration Associates 2 (collectively, 'QFs') pursuant to contrcts approved by the Commission before the effective date
of this policy and procedure.
2. EFFECTIVE DATE: This policy and procedure shall take effect on the date of entr by the Commission of an Order resolving
the issues raised by the complaints identified as Docket Nos. 93-5037/93-5067/93-5068.
3. DEFINTIONS: The following definitions shall apply to this policy and procedure:
Base Load Resources: (a) any present and future NPC coal-fired generation, including, but not limited to, NPC's ownership
portion of Mohave, Reid Gardner, and Navajo, at normal operating levels and consistent with EPA requirements, (b) any 10ng-
term take-or-pay base load purchase contracts, and those contracts which are obtained in order to temporarily replace a base
load resource that is off line as part of a regularly scheduled maintenance outage, (c) NPC's allocation of Hoover, (d) QFs with
non-dispatchable long-term contracts, including Saguaro, NCA 1, NCA 2, and, to a limited extent, Las Vegas Cogeneration
Associates, (e) test energy required to make any NPC or non-NPC resources available to NPC, and (t) resources required for
system regulation.
System Load: NPC's system load includes that of its end-use customers which it bills for various services, the load of the City of
Needles, California, and the loads ofa gold mine west of Searchlight. System load also includes some of the loads of Boulder
City, Valley Electrc, Overton Power District, and Lincoln County Power Distnct (collectively, the Silver State loads).
*14 System Regulation: System regulation includes, but is not limited to, the obligation ofNPC to have resources on line to
support load following, voltage and reactive power support, required system reserve margins, system protection, and resources
requires to meet NPC's ara control responsibilties.
Proportional Energy Curtailment: The energy not taken, calculated at the contract capacity for the QFs, such that the energy
not taken wil be, as close as reasonably possible, the same percentage for each of the base load QFs.
4. NPC may reduce the output or isolate a QF's generating facility to the extent and for the time necessary to correct the condition
which necessitated the reduction or isolation when, in NPC's reasonable judgment, a condition or conditions exist(s) which may
affect the integrity, secunty, or reliability ofNPC's electrical system, and/or the health and safety of people.
5. NPC may curtail a QF, when, due to operational circumstances (including low or light loading), purchases from a QF would
result in costs greater thn those NPC would otherwse incur by generating or purchasing an equivalent amount of energy,
except that purchases of economy energy will be reduced to zero.
6. NPC wil determine that a low or light load condition exists when no resources, other th base load resources, are being used
by NPC for its system load. Economy purchases wil have been reduced to zero. Resources which are not base load resources
wil have been taken offline.
7. When a low or light loading situation exists as described hereinabove, NPC shall curtail the QFs, subject to the following:
(a) Hoover allocation. Under normal circumstances, delivery of Hoover energy will be reduced to minimum regulating level,
except when required to meet predetermined monthly allocations provided by the Western Area Power Administration. Under
no circumstances shall Hoover energy be curtiled in a manner which would jeopardize the long-term availabilty of the Hoover
resource allocation.
(b) NPC shall provide a minimum of one hour's notice to each QF prior to curtailment. As a matter of practice, NPC shall
provide as much notice as reasonably possible so as to mitigate the impact such curtailment may have on the QF.
1-03
Saguaro Power Co. v. Nevada Power Co., 1994 WL 780897 (1994)
(c) NPC shall use its best efforts to schedule test energy in a mar which will miimize impact of culments on QFs.
(d) NPC shall maintain a record of cumulative QF curilment hour. This record shall include data regarding the loading of
all units prior to, during, and aft each period of curtilment.
8. QFs shall be curled in the following maner:
(a) All QFs shall initially be reduced to contract capacity.
(b) In administering curtailments below the contract capacity, NPC shal endeavor to eqalize the proporional energy
curtilment of the base load QFs.
(c) To the extent reasonably feasible, the cuailments ofQFs will be tempered by consideration of the steam hosts which ar
dependent on each QF for stem and/or heat, provided that NPC is privy to inormation from the QFs and/or their hosts, upon
which it could make such judgments.
*15 (d) Curailments shall be limited to the anual levels set fort-in each long-term QF contrct in the tie periods to the
extent possible specified in each QF contract.
(e) Curtailments related to system integrty, reliability, or regulation shall be limited to the extent possible.
End of llocument ,ç; :Wl I Thomson Reuters. No claim w original U,S, Govcmmcnl Works.
1-03
T. Park, IPC
Page 2 of2
BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
CASE NO. GNR-E-11-03
IDAHO POWER COMPANY
PARK, 01
TESTIMONY
EXHIBIT NO.5
Idaho Power Company
I.P.U.C. No. 29. Tariff No. 101 Original Sheet No. 74-1
SCHEDULE 74
POLICY AND PROCEDURE FOR OPERATIONAL DISPATCH
OF CERTAIN PURPA QUALIFYING FACILITIES
APPLICABILITY
This policy and procedure shall govern the operational dispatch by the Company of the capacity
and energy which may be made available by all qualifying facility ("QF") generators interconnected to
the Company that have a nameplate capacity of 10 MW or more and that have Generator Output
Limiting Controls ("GOLCs").
DEFINITIONS
Base Load Resources. Company-owned hydroelectric resources, including all run-of-river
generators and the Hells Canyon Complex, coal-fired generating resources (Jim Bridger generating
plant, Valmy generating plant, and the Boardman generating plant), and the Langley Gulch power plant.
Applicable Qualifying Facilties or Applicable QFs. All QF generators interconnected to the
Company's electrical system that have a nameplate capacity of 10 MW or more and that have GOLCs.
Must Run Periods. Those periods when the Company's system load demand in the upcoming
hours and days requires that suffcient Base Load Resources wil be on-line and available to serve
system load.
CURTAILMENT
The Company may curtail the generation of an Applicable QF during Must Run Periods if, due to
operational circumstances, purchases from the Applicable QF would require the Company to dispatch
higher cost, less efficient resources to serve system load or to make Base Load Resources unavailable
for serving the next anticipated load. Prior to curtailng the Applicable QFs, the Company shall operate
its Base Load Resources as follows:
1. Resources which are not Base Load Resources wil be taken off-line prior to
curtailment of any Applicable QF generation.
2. The Company wil take all generation produced by its run-of-river hydroelectric
resources at the time of the curtailment. .
3. Generation at the Hells Canyon Complex shall be reduced to minimum regulating
levels within then-applicable environmental requirements.
4. The Company's thermal generating resources shall be backed down to suffcient
generating levels so as to stil be able to ramp up generation to meet anticipated system load.
Exhibit NO.5
Case No. GNR-E-11-03
T. Park, IPC
Page 1 of2
IDAHO
Issued per Order No.
Effective -
Issued by IDAHO POWER COMPANY
Gregory W. Said, Vice President, Regulatory Affairs
1221 West Idaho Street, Boise, Idaho
Idaho Power Company
I.P.U.C. No. 29. Tarif No. 101 Onginal Sheet No. 74-2
SCHEDULE 74
POLICY AND PROCEDURE FOR OPERATIONAL DISPATCH
OF CERTAIN PURPA QUALIFYING FACILITIES
(Continued)
CURTAILMENT (Continued)
Procedures
Applicable QFs shall be curtailed as follows:
1. Dunng Must Run Periods, the Company shall curtail the output of all Applicable
QFs on a pro rata basis.
2. Applicable QF output shall be curtailed only for the time period necessary during
Must Run Periods wherein the Company is not forced to make Base Load Resources
unavailable for serving the next anticipated load, nor dispatch less efficient, higher cost
resources to serve system load.
NOTICE AND RECORDKEEPING
When Must Run Periods exist, the Company shall curtail the Applicable QF as follows:
1. The Company shall provide a minimum of one hour's prior notice to each
Applicable QF prior to curtailment. As a matter of practice, the Company shall use commercially
reasonable efforts to provide such notice as soon as reasonably possible so as to mitigate the
impact such curtailment may have on the Applicable QFs.
2. At the end of the curtailment period, the Company shall provide notice to all
Applicable QFs that were curtailed of the total time their generators were curtailed.
3. The Company shall maintain a record of cumulative QF curtailment hours. This
record shall include data regarding the loading of all generation units interconnected to the
Company's system prior to, dunng, and after each period of curtailment.
Exhibit No. 5
Case No. GNR-E-11-03
T. Park, IPC
Page 2 of2
IDAHO
Issued per Order No.
Effective -
Issued by IDAHO POWER COMPANY
Gregory W. Said, Vice President, Regulatory Affairs
1221 West Idaho Street, Boise, Idaho
CERTIFICATE OF SERVICE
I HEREBY CERTIFY that on the 31st day of January 2012 I served a true and
correct copy of the DIRECT 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
PacifiCorp d/b/a Rocky Mountain Power
Daniel E. Solander
PacifiCorp d/b/a Rocky Mountain Power
201 South Main Street, Suite 2300
Salt Lake City, Utah 84111
Kenneth Kaufmann
LOVINGER KAUFMANN, LLP
825 NE Multnomah, Suite 925
Portland, Oregon 97232
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 2th Street (83702)
P.O. Box 7218
Boise, Idaho 83707
CERTIFICATE OF SERVICE-1
-2 Hand Delivered
U.S. Mail
_ Overnight Mail
FAX
-2 Email don. howellCâpuc. idaho .gov
kris. sasserCâpuc. idaho. gov
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U.S. Mail
_ Overnight Mail
FAX
-2 Email michael.andreaCâavistacorp.com
Hand Delivered
U.S. Mail
_ Overnight Mail
FAX
-2 Email daniel.solanderCâpacificorp.com
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U.S. Mail
_ Overnight Mail
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-2 Email kaufmannCâlklaw.com
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U.S. Mail
_ Overnight Mail
FAX
-2 Email peterCârichardsonandoleary.com
gregCârichardsonandoleary.com
Exergy Development Group
James Carkulis, Managing Member
Exergy Development Group of Idaho, LLC
802 West Bannock Street, Suite 1200
Boise, Idaho 83702
Hand Delivered
U.S. Mail
_ Overnight Mail
FAX
-l Emall icarkulis~exergydevelopment.com
Grand View Solar II
Robert A. Paul
Grand View Solar II
15690 Vista Circle
Desert Hot Springs, California 92241
Hand Delivered
U.S. Mail
_ Overnight Mail
FAX
-l Email robertapaul08~gmail.com
J.R. Simplot Company
Don Sturtevant, Energy Director
J.R. Simplot Company
One Capital Center
999 Main Street
P.O. Box 27
Boise, Idaho 83707-0027
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U.S. Mail
_ Overnight Mail
FAX
-l Email don.sturtevant~simplot.com
Northwest and Intermountain Power
Producers Coalition
Robert D. Kahn, Executive Director
Northwest and Intermountain Power
Producers Coalition
1117 Minor Avenue, Suite 300
Seattle, Washington 98101
Hand Delivered
U.S. Mail
_ Overnight Mail
FAX
-l Email rkahn~nippc.org
Board of Commissioners of Adams
County, Idaho
Bil Brown, Chair
Board of Commissioners of
Adams County, Idaho
P.O. Box 48
Council, Idaho 83612
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U.S. Mail
_ Overnight Mail
FAX
-l Email bdbrown~frontiernet.net
Clearwater Paper Corporation
Marv Lewallen
Clearwater Paper Corporation
601 West Riverside Avenue, Suite 1100
Spokane, Washington 99201
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_ Overnight Mail
FAX
-l Email marv.lewallen~c1earwaterpaper.com
CERTIFICATE OF SERVICE - 2
Renewable Energy Coalition
Thomas H. Nelson, Attorney
P.O. Box 1211
Welches, Oregon 97067-1211
Hand Delivered
U.S. Mail
_ Overnight Mail
FAX
-- Email nelsoncæthneslon.com
John R. Lowe, Consultant
Renewable Energy Coalition
12050 SW Tremont Street
Portland, Oregon 97225
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U.S. Mail
_ Overnight Mail
FAX
-- Email jravenesanmarcoscæyahoo.com
Dynamis Energy, LLC
Ronald L. Wiliams
WILLIAMS BRADBURY, P.C.
1015 West Hays Street
Boise, Idaho 83702
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U.S. Mail
_ Overnight Mail
FAX
-- Email roncæwilliamsbradbury.com
Wade Thomas, General Counsel
Dynamis Energy, LLC
776 East Riverside Drive, Suite 150
Eagle, Idaho 83616
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U.S. Mail
_ Overnight Mail
FAX
-- Email wthomas(cdynamisenergy.com
Idaho Windfarms, LLC
Glenn Ikemoto
Margaret Rueger
Idaho Windfarms, LLC
672 Blair Avenue
Piedmont, California 94611
Hand Delivered
U.S. Mail
_ Overnight Mail
FAX
-- Email glenni(cenvisionwind.com
margaret(cenvisionwind .com
Interconnect Solar Development, LLC
R. Greg Ferney
MIMURA LAW OFFICES, PLLC
2176 East Franklin Road, Suite 120
Meridian, Idaho 83642
Hand Delivered
U.S. Mail
_ Overnight Mail
FAX
-- Email greg(cmimuralaw.com
Bil Piske, Manager
Interconnect Solar Development, LLC
1303 East Carter
Boise, Idaho 83706
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_ Overnight Mail
FAX
-- Email bilpiske(ccableone.net
CERTIFICATE OF SERVICE - 3
Renewable Northwest Project
Dean J. Miller
McDEVITT & MILLER LLP
420 West Bannock Street (83702)
P.O. Box 2564
Boise, Idaho 83701
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_ Overnight Mail
FAX
-- Email joe(âmcdevitt-miler.com
Megan Walseth Decker
Senior Staff Counsel
Renewable Northwest Project
917 SW Oak Street, Suite 303
Portland, Oregon 97205
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_ Overnight Mail
FAX
-. Email megan(ârnp.org
North Side Canal Company and Twin Falls
Canal Company
Shelley M. Davis
BARKER ROSHOLT & SIMPSON, LLP
1010 West Jefferson Street, Suite 102 (83702)
P.O. Box 2139
Boise, Idaho 83701-2139
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-- Email smd(âidahowaters.com
Brian Olmstead, General Manager
Twin Falls Canal Company
P.O. Box 326
Twin Falls, Idaho 83303
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_ Overnight Mail
FAX
-- Email olmstead(âtfcanal.com
Ted Diehl, General Manager
North Side Canal Company
921 North Lincoln Street
Jerome, Idaho 83338
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_ Overnight Mail
FAX
-- Email nscanal(âcableone.net
Birch Power Company
Ted S. Sorenson, P.E.
Birch Power Company
5203 South 11 th East
Idaho Falls, Idaho 83404
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_ Overnight Mail
FAX
-- Email ted(âtsorenson.net
Blue Ribbon Energy LLC
M. J. Humphries
Blue Ribbon Energy LLC
4515 South Ammon Road
Ammon, Idaho 83406
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_ Overnight Mail
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-- Email blueribbonenergy(âgmail.com
CERTIFICATE OF SERVICE - 4
Arron F. Jepson
Blue Ribbon Energy LLC
10660 South 540 East
Sandy, Utah 84070
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FAX
~ Email arronesq(ãaol.com
Idaho Conservation League
Benjamin J. Otto
Idaho Conservation League
710 North Sixth Street (83702)
P.O. Box 844
Boise, Idaho 83701
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.1 Email botto(ãidahoconservation.org
Snake River Allance
Ken Miler
Clean Energy Program Director
Snake River Alliance
350 North 9th Street #B61 0
P.O. Box 1731
Boise, Idaho 83701
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.1 Email kmiller(ãsnakeriveralliance.org
4c¿c(~Donovan E. Walker
CERTIFICATE OF SERVICE - 5