20120131Bokenkamp Direct.pdf

RECEIVED
2012 JAN 31 PM 3: 24
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-ll-03
IDAHO POWER COMPANY
DIRECT TESTIMONY
OF
KARL BOKENKAP
1 Q.Please state your name and business address.
2 A.My name is Karl Bokenkamp and my business
3 address is 1221 West Idaho Street, Boise, Idaho.
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 Operations
7 Strategy.
8 Q .Please describe your educational background.
9 A.I received a Bachelor of Science Degree in
10 Mechanical Engineering from the Uni versi ty of Illinois at
11 Urbana-Champaign in 1980. In 1995, I earned a Master of
12 Engineering Degree in Mechanical Engineering from the
13 Uni versi ty of Idaho and, in 2010, I received a Master of
14 Business Administration from Boise State Uni versi ty. I am
15 a registered Professional Engineer in the state of Arizona,
16 and I have attended the Stone & Webster Utility Management
17 Development Program and the Uni versi ty of Idaho's Utility
18 Executive Course.
19 Q.Please describe your work experience with
20 Idaho Power.
21 A.I was employed by Idaho Power in 1995 as the
22 Director, and then Manager, of Thermal Production. In this
23 position, I was responsible for managing Idaho Power's
24 Thermal Production Department. Primary responsibilities of
25 the department included oversight and control of Idaho
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Idaho Power Company
1 Power's ownership shares in its three jointly owned coal-
2 fired generation resources, Bridger, Boardman, and Valmy,
3 and their associated fuel supplies.
4 In 2001, I accepted a new position as the Manager of
5 Power Supply Planning and was later promoted to General
6 Manager of Power Supply Planning. In this position, I was
7 responsible for building and managing Power Supply's
8 Planning Department. This department' s responsibilities
9 included operational planning, load forecasting, stream
10 flow forecasting, integrated resource planning,
11 cogeneration and small power producer contract management,
12 water management/river operations, and gas and coal
13 contract management.
14 In 2006, I was promoted to the position of General
15 Manager, Power Supply Operations and Planning. This
16 position added operational responsibilities, which included
17 asset optimization, wholesale electricity, and natural gas
18 transactions from real-time through multi-year deals as
19 well as real-time operations and scheduling.
20 In 2010, I became Idaho Power's Director of
21 Operations Strategy. In this position, I am responsible
22 for unifying Idaho Power's operational strategy, including
23 sustainabili ty, investigating opportunities, trends and
24 technologies that may impact the utility business, and
25
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Idaho Power Company
1 posi tioning the Company for continued success in its
2 rapidly changing industry.
3 Q.What is the purpose of your testimony in this
4 proceeding?
5 A.I will present Idaho Power's proposal for
6 modifications to the existing Integrated Resource Plan-
7 ("IRP") based avoided cost pricing methodology. There are
8 two primary changes I am proposing; they are (1) a change
9 in the methodology used to determine the energy component
10 of avoided cost and (2) a change in the resource type used
11 to establish the capacity component of avoided cost.
12 CURNT METHODOLOGIES
13 Q.What avoided cost methodologies are currently
14 approved by the Idaho Public Utili ties Commission
15 ("Commission") for determining avoided cost rates for
16 Qualifying Facility ("QF") contracts?
1 7 A.As discussed more fully in Company witness
18 Mark Stokes' testimony, the Commission has approved two
19 methodologies for establishing a utility's avoided cost and
20 setting rates for QF contracts entered into pursuant to
21 Public Utility Regulatory Policies Act of 1978 ("PURPA")
22 regulations. The two methodologies are the Surrogate
23 Avoided Resource ("SAR") methodology and the IRP
24 methodology.
25 Q.What is the SAR methodology?
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Idaho Power Company
1 A.The SAR methodology is a methodology which
2 uses a surrogate or proxy resource to set published, or
3 standard, avoided cost rates. As currently implemented in
4 Idaho, the SAR methodology uses a natural gas-fired
5 combined cycle combustion turbine as the surrogate resource
6 for establishing rates for QF contracts. Published, or
7 standard, rates are required by Federal Energy Regulatory
8 Commission for projects up to 100 kilowatts ("kW").
9 Published rates in Idaho are available to wind and solar
10 QFs with a nameplate capacity up to 100 kW and all other
11 QFs with an output of up to 10 average megawatts ("aMW")
12 per month. All QF proj ects over 10 aMW and all wind and
13 solar QF proj ects over 100 kW must use the IRP-based
14 methodology, which provides a basis for developing a
15 negotiated rate.
16 Q.Does the Company have any recommendations
17 regarding the use of the SAR methodology?
18 A.Yes. Idaho Power proposes that the
19 Commission discontinue use of the SAR methodology for
20 establishing avoided cost rates, and instead proposes that
21 the Commission utilize the IRP-based methodology to
22 establish all QF avoided cost rates. The rationale for
23 this position is set forth in more detail in the testimony
24 of Company witness Stokes.
25 Q.What is the IRP methodology?
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Idaho Power Company
1 A.The IRP methodology is the second of the two
2 methodologies the Commission has approved for establishing
3 a utility's avoided cost pursuant to PURPA. Generally, the
4 IRP-based methodology calculates the proj ected future cost
5 of Idaho Power's preferred resource portfolio without the
6 QF seeking contract pricing, and then again with the QF
7 seeking contract pricing added to the resource portfolio at
8 zero cost. The difference in cost between the two analyses
9 is divided by the proj ected QF generation to determine the
10 energy component of avoided cost. The capacity component
11 of avoided cost is determined based on the characteristics
12 of the QFs generation, and it is added to the energy
13 component. This methodology produces an estimate of the
14 utility's avoided cost, which is then used as the starting
15 point for negotiating QF contract pricing. Proj ect-
16 specific characteristics are utilized in the pricing
17 analysis and a number of other factors can enter into
18 contract negotiations. Idaho Power's current approach for
19 implementing the IRP methodology was presented to the
20 parties of this case on December 15, 2011, in the
21 Commission's hearing room, and is explained in greater
22 detail in Company witness Stokes' testimony and Stokes'
23 Exhibit No.3.
24
25
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Idaho Power Company
1 Q.Is it Idaho Power's position that the IRP
2 methodology is a better estimation of avoided cost than the
3 SAR methodology?
4 A.Yes. The IRP methodology as currently
5 implemented is a significant improvement over the SAR
6 methodology. It is a far more accurate approximation of
7 avoided cost than the more generic SAR methodology. As
8 currently implemented, the IRP methodology begins to take
9 into account some aspects of need, value, and timing of the
10 QFs proposed generation when establishing the avoided cost
11 rates. One of the most important improvements of the IRP
12 methodology over the SAR methodology is that the IRP
13 methodology incorporates several of the resource-specific
14 characteristics of the proposed QF generation. These
15 include the QF's specific generation output profile, a
16 resource specific capacity factor, the timing of
17 anticipated generation, and a capacity credit based on the
18 anticipated amount of capacity provided during Idaho
19 Power's projected peak-load hours.
20 Q.Do you have any recommendations for changing
21 the current implementation of the IRP methodology?
22 A.Yes. While the IRP methodology as currently
23 implemented by Idaho Power is a significant improvement
24 over the SAR methodology, it still has a number of problems
25 that result in significant harm to Idaho Power's customers.
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Idaho Power Company
1 Q.Could you please provide us with some examples
2 of the problems that exist with the current implementation
3 of the IRP methodology?
4 A.Yes. Although the IRP methodology is a
5 significant improvement over the SAR methodology it does
6 have several flaws that disconnect it from the definition
7 of avoided cost as set forth in federal regulations, which
8 is what the IRP methodology is supposed to be
9 approximating. For example, as currently implemented by
10 Idaho Power:
11 1.The avoided cost produced by the
12 current IRP methodology relies too heavily upon forecasts
13 of future market prices. Under the current approach,
14 customers take on a significant amount of a market price
15 risk that, but for the QF purchase, they normally would not
16 experience as a customer of Idaho Power.
17 2.The avoided cost produced by the IRP
18 methodology, is largely predicated on making surplus sales
19 at the future market prices developed within the AURORA
20 model. This deviates from the definition of avoided cost,
21 which is focused on the incremental cost to an electric
22 utility of displaced generation or purchases. Proj ected
23 revenue from surplus sales is never mentioned in the
24 federal regulation definition of avoided cost.
25
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Idaho Power Company
1 3.The present IRP methodology is somewhat
2 static with respect to changes in the resource portfolio.
3 What I mean by this is that the preferred resource
4 portfolio used in the IRP methodology is not updated
5 between IRP cycles. Consequently, the impacts of newly
6 signed QF contracts on Idaho Power's avoided cost are not
7 reflected in subsequent avoided cost calculations until the
8 preferred portfolio is updated in the next IRP cycle.
9 Q.You have mentioned the definition of avoided
10 costs several times, what are you referring to?
11 A.I am referring to the definition of avoided
12 cost found in federal regulations, 18 C. F. R. §
13 292.101(b)(6).
14 Q.How do the federal regulations define
15 avoided cost for purposes of PURPA QFs?
16 A.Federal regulation defines avoided cost as
17 follows:
18 Avoided costs means the incremental costs19 to an electric utility of electric energy20 or capacity or both which, but for the21 purchase from the qualifying facility or22 qualifying facilities, such utility would23 generate itself or purchase from another24 source.
2526 18 C.F.R. § 292.101(b)(6).
27 Q.What is significant about this definition?
28 A.First of all, the concept of identifying
29 incremental costs the utility would incur, but for the QF
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Idaho Power Company
1 purchase, is clearly significant. This concept is the key
2 to developing an avoided cost methodology that accurately
3 calculates avoided cost as contemplated by, and required
4 by, federal law. Another significant aspect of the
5 definition is the absence of any reference to sales in
6 determination of avoided costs.
7 Q.Do you have any other observations or
8 comments of significance about the definition of avoided
9 cost?
10 A.Yes. Keeping with the definition of avoided
11 cost, what Idaho Power is trying to determine is the
12 incremental costs to an electric utility which, but for the
13 purchase from the QF, such utility would generate itself or
14 purchase from another source. At a very basic level, this
15 definition implies that the utility needs to incur, or at
16 least expect to incur, a cost in order to have an avoided
17 cost. With this in mind, Idaho Power's proposed revision
18 to the IRP methodology focuses on identifying the
19 incremental costs that its system would incur, but for the
20 QF purchase, to generate power itself or to purchase power
21 from another source. This directly comports with the
22 definition of avoided cost from federal regulations.
23 Since incremental costs change, a proper application of the
24 Code of Federal Regulation's definition of avoided cost
25 results in (1) an hour-by-hour analysis of the period of
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Idaho Power Company
1 interest to determine the avoidable incremental cost during
2 each hour and then (2) a methodology to convert the hourly
3 incremental costs into avoided cost rates. Idaho Power's
4 proposed avoided cost methodology addresses both of these
5 items.
6 PROPOSED IRP METHODOLOGY MODIFICATIONS
7 Q.Please describe Idaho Power's proposed
8 modifications to the IRP based methodology.
9 A.Idaho Power's proposed modifications to the
10 IRP methodology are as follows:
11 1.A change in the methodology used to
12 determine the energy component of avoided cost. This
13 change is proposed in order to align the methodology with
14 the federal regulation's definition of avoided cost and
15 thereby establish an avoided cost of energy based on the
16 incremental costs the utility would incur, but for the
17 addi tion of the QF resource;
18 2.A change in the resource type used to
19 establish the capacity component of avoided cost. This
20 change is proposed to align the methodology with the actual
21 costs of capacity that are avoided; and
22 3.Implementation of a queuing process to
23 (1) establish a QF's position in line and (2) identify the
24 QF proj ects included in Idaho Power's resource portfolio
25 for determining avoided costs in subsequent requests for QF
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Idaho Power Company
1 contract pricing. Idaho Power's resource portfolio, for
2 purposes of calculating a future avoided cost, can change
3 whenever a QF proj ect enters the queue if that QF is
4 considered as a part of the resource portfolio.
5 Accordingly, the avoided cost of energy and capacity can
6 change for each new QF as a result of the capacity and
7 energy provided by all proj ects in Idaho Power's portfolio,
8 including any QFs already in the queue. The fact that
9 avoided costs can change as new QF resources are added to
10 the portfolio must be taken into account if avoided cost is
11 to be determined properly.
12 AVOIDED COST OF ENERGY
13 Q.Please describe in more detail the
14 particular changes you are proposing to the current
15 implementation of the IRP methodology.
16 A.As discussed in Company witness Stokes'
17 testimony, the IRP methodology includes a rate for both the
18 avoided cost of energy and the avoided cost of capacity.
19 In order to align with the required definition of avoided
20 costs, Idaho Power proposes that the avoided cost of energy
21 be based upon the incremental energy cost the utility would
22 incur, but for the QF output. In order to do this, Idaho
23 Power proposes to use the AURORA model to determine the
24 highest displaceable incremental cost being incurred during
25 each hour of the QF's proposed contract term. In Idaho
BOKENKAP, DIll
Idaho Power Company
1 Power's proposal, displaceable incremental costs are
2 limi ted to (1) incremental costs for Company-owned thermal
3 resources (Bridger, Boardman, Valmy, Langley Gulch, and the
4 gas-fired peakers) that are on-line and operating at above
5 their minimum load level, (2) the incremental cost
6 associated with longer-term firm purchases, and (3) the
7 incremental cost of market purchases as determined by
8 AURORA.
9 Q.Could you explain what you mean when you say
10 that displaceable incremental costs are limited to the
11 incremental costs for Company-owned thermal resources or
12 the incremental costs associated longer-term firm purchases
13 or market purchases?
14 A.Yes. First, for a resource to be
15 "displaceable" it has to be on-line and capable of staying
16 on - line and further reducing its output. Second, the
17 displaceable incremental costs associated with any longer-
18 term firm purchases or market purchases are set at the
19 market clearing price as determined by the AURORA model on
20 an hour-to-hour basis.
21 Q.How are longer-term firm, non-PURPA, power
22 purchases treated in the model?
23 A.Longer-term firm purchases, such as the PPL
24 EnergyPlus Power Purchase Contract, will be included in
25 Idaho Power's resource portfolio in the AURORA model to
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Idaho Power Company
1 determine the avoided cost of energy, and they will be
2 modeled as must run resources. However, during any hours
3 when purchases under these contracts are flowing, the
4 market clearing price determined in AURORA will be used to
5 establish the displaceable incremental cost associated with
6 that firm purchase. For example, if the firm purchase is
7 resold at market price and the QF generation is accepted,
8 then the incremental cost avoided is the net proceeds from
9 the resale of the firm purchase after any transaction-
10 related costs such as transmission costs, losses, etc.
11 However, to simplify the analysis, Idaho Power is proposing
12 to disregard the transaction-related costs and use the
13 AURORA market clearing price to set the displaceable
14 incremental cost for long-term firm, non-PURPA, power
15 purchases whenever they are flowing.
16 Q.You have mentioned that displaceable
17 incremental costs are limited to the incremental costs for
18 Company-owned thermal resources and the incremental costs
19 associated with longer-term firm purchases or market
20 purchases. What about Idaho Power's hydroelectric proj ects
21 - are their incremental costs considered in the methodology
22 Idaho Power is proposing?
23 A.No. The direct operating expense for Idaho
24 Power's hydroelectric resources during 2011, including an
25 estimate of depreciation (which was over $15 million), was
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I daho Power Company
1 approximately $31 million. Idaho Power's 2011
2 hydroelectric generation was approximately 11 million
3 megawatt-hours ("MWh"). This gives Idaho Power an
4 operating cost in 2011, including depreciation, of
5 approximately $3/MWh. Without considering depreciation,
6 hydro operating expenses are less than $1. 50/MWh, and
7 variable costs are even less. Since Idaho Power typically
8 has one or more thermal units on-line, and since the
9 incremental cost of the thermal units always exceed the
10 variable cost of the hydro units, I have not considered the
11 incremental cost of Idaho Power's hydroelectric resources
12 in this methodology. If opportunity costs are included and
13 shifting hydro generation from one time period to another
14 is considered, the analysis becomes more complicated. In a
15 practical sense, the incremental cost avoided in any given
16 hour, as a result of displacing a MWh of hydroelectric
17 generation during that hour, is very small. With this in
18 mind, the methodology I am proposing does not attempt to
19 incorporate the incremental cost of Idaho Power's
20 hydroelectric proj ects.
21 Q.Are there times when the incremental cost
22 calculated with Idaho Power's proposed methodology goes to
23 zero?
24 A.Yes, and this is not unrealistic.
25 Considering the minimum load levels established for the
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Idaho Power Company
1 thermal generating resources, and the amount of non-
2 dispatchable QF generation on Idaho Power's system, there
3 may be hours during low load periods when Idaho Power's
4 avoidable incremental costs are zero. In fact, there could
5 be times when Idaho Power's avoided incremental costs would
6 be negative. For example, if loads are low and a thermal
7 unit is shutdown in order to accept additional QF
8 generation and then the output of the intermittent QF
9 generation drops off, additional costs could be incurred if
10 the previously shutdown thermal unit is unavailable to
11 replace the QF output. A more expensive unit may have to
12 be started or more expensive market purchases may be
13 required. In ei ther situation, additional costs are
14 incurred.
15 Q.Do you have an example?
16 A.Yes. As an example, out of a total of
17 157,776 hours in an AURORA simulation for a 22 megawatt
18 ("MW") wind project, the new methodology assigned an
19 avoided cost of $O/MWh in 1,563 hours. This works out to
20 about 1 percent of the time, or 87 hours per year.
21 Q.Would Idaho Power be able to sell the output
22 from the QF during that hour?
23 A.Maybe, but if the model has the Company's
24 available coal-fired units at their minimum loads and if
25 there are not transmission constraints limiting their
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Idaho Power Company
1 output, then there likely is not a demand for energy at the
2 coal -fired units dispatch prices.
3 Q.Can you provide an example to demonstrate
4 your proposed change in the way the avoided cost of energy
5 is calculated?
6 A.Yes. Idaho Power can look at several
7 different hypothetical cases to illustrate how the
8 methodology will assign incremental costs. For example, in
9 case 1 load is 2,000 MW, the system is balanced, Idaho
10 Power has one or more thermal units in operation, and there
11 are no purchases; in case 2, identical conditions exist
12 with the following exception, a "new" QF generates and
13 delivers one MWh of energy to Idaho Power's system. One of
14 two things must happen for the system to remain balanced
15 either Idaho Power's resources must reduce output by one
16 MWh or one MWh is sold into the market. If a sale is made,
17 there is no incremental cost to Idaho Power that is
18 avoided. However, if the output of Idaho Power's highest
19 cost on-line thermal resource can be reduced by one MWh,
20 then there is an incremental cost to Idaho Power that can
21 be avoided. If the incremental costs of that unit are
22 $17 /MWh for fuel and $3/MWh for variable operations and
23 maintenance, then the avoided cost for that MWh of QF
24 energy is $20/MWh ($17 /MWh + $3/MWh).
25
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Idaho Power Company
1 If the on-line thermal resources are at their
2 established minimum load levels, thermal generation cannot
3 be further reduced without taking a unit off-line. In this
4 situation, if a QF produced an additional MWh and Idaho
5 Power took a thermal unit off-line to accommodate the QF
6 generation and then later had to restart the unit because
7 of reduced QF output or increased load, the additional MWh
8 of QF generation could have resulted in Idaho Power
9 actually incurring more costs than it would have without
10 recei ving the QF generation. Under these circumstances,
11 the methodology assumes generation at one of the hydro
12 projects is reduced and water is spilled. In this case,
13 the cost to Idaho Power if it had generated that MWh of
14 energy at one of its hydro proj ects is essentially zero and
15 the incremental cost avoided is set at $O/MWh for that
16 hour.
17 Assuming a different hypothetical situation, again
18 using two cases: in case 1, load is 3,000 MW, the system
19 is balanced, Idaho Power has one or more thermal units in
20 operation, and purchases are being made to serve load; in
21 case 2, identical conditions exist with the following
22 exception, a "new" QF generates and delivers one MWh of
23 energy to Idaho Power's system. For the system to remain
24 balanced in case 2, one of three things must happen - Idaho
25 Power's resources must reduce output by one MWh, market
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Idaho Power Company
1 purchases must be reduced by one MWh, or one MWh must be
2 sold into the market. Like before, if a sale is made, no
3 incremental costs are avoided as a result of receipt of the
4 QF energy. However, if the output of one of Idaho Power's
5 thermal resources is reduced by one MWh, or if the amount
6 of market purchases are reduced by one MWh, then it is
7 possible to identify an incremental cost that the utility
8 would have incurred, but for the "new" QF purchase. In
9 this instance, the incremental cost avoided during that
10 hour is the greater of (1) the incremental cost of the most
11 expensive displaceable thermal resource on-line or (2) the
12 market clearing price during that hour. For example, if
13 the incremental cost of the most expensive thermal unit on-
14 line is $20/MWh (the same unit described earlier) and the
15 most expensive market purchases during the same hour is
16 $30/MWh, then the avoided cost for that MWh of energy is
17 $30/MWh. Alternatively, if the incremental cost of the
18 most expensive thermal unit on-line is $60/MWh (e.g., a
19 simple cycle combustion turbine ("SCCT") with 11,000
20 Btu/kWh heat rate, $5. OO/MMBtu natural gas, and variable
21 operations and maintenance ("O&M") costs of $5/MWh) and the
22 cost of market purchases during the same hour is $30/MWh,
23 then the avoided cost for that MWh of energy is $60/MWh.
24
25
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Idaho Power Company
1 Q.Could you summarize how Idaho Power's
2 proposed modification to the calculation of the avoided
3 cost of energy works?
4 A.Yes. To calculate the energy component of
5 avoided cost, the incremental cost for each hour of the
6 proposed QF contract term is determined by analyzing the
7 resul ts of the AURORA analysis as described above. The
8 result of that analysis is a time series of displaceable
9 incremental or avoided costs - one for each hour of the
10 proposed contract term. This time series of hourly avoided
11 costs is then multiplied by the QF's supplied hourly
12 generation profile; e. g., avoided cost in hour 1 x QF
13 forecast generation in hour 1, avoided cost in hour 2 x QF
14 forecast generation in hour 2, etc. These products are
15 then summed over heavy load and light load hours of each
16 month and divided by the corresponding forecast QF
17 generation. The result is a heavy load and light load
18 price for each month of the contract term.
19 Q.How is this any different than the way the
20 avoided cost of energy is currently calculated?
21 A.Under the current methodology, the power
22 supply costs of Idaho Power's resource portfolio are
23 determined by the AURORA model without inclusion of the
24 proposed QF. Then the AURORA model is run a second time
25 with no modifications to the dispatch of Idaho Power's
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Idaho Power Company
1 resources (e. g., Bridger, Boardman, Valmy, Hells Canyon,
2 and all other resources produce the same hourly output they
3 did in the first AURORA simulation) and the proposed QF's
4 generation is added to the resource portfolio at zero cost.
5 Because the load and operation of Idaho Power's resources
6 are the same, the QF generation is used for one of two
7 things - it either displaces a market purchase or supplies
8 a market sale.
9 Under the new methodology, there is only one AURORA
10 model run which is used to determine the displaceable
11 incremental or avoided cost for each hour. These hourly
12 avoided costs and the QF's supplied hourly generation
13 profile are then used to determine monthly heavy load and
14 light load pricing for the QF contract. Under this
15 methodology, the incremental costs that Idaho Power would
16 have incurred but for the QF generation is the basis for QF
17 contract pricing. In both the current implementation of
18 the IRP methodology and Idaho Power's proposed change to
19 that methodology, QF generation is used to displace
20 purchases. When purchases are displaced, the QF generation
21 is valued at the cost of the displaced purchase. However,
22 in the modified methodology, if the QF generation is not
23 used to displace a purchase (a cost that Idaho Power would
24 have incurred, but for the QF generation), it is used to
25 displace one of Idaho Power's thermal resources (another
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Idaho Power Company
1 cost that Idaho Power would have incurred but for the QF
2 generation). Under the proposed methodology, the QF
3 generation is not used to make market sales at AURORA-
4 generated market clearing prices.
5 Q.Could you summarize the differences?
6 A.In summary, the main difference is that in
7 Idaho Power's current implementation of the IRP
8 methodology, the QF generation supports market sales which
9 generate revenues that reduce Idaho Power's calculated
10 power supply costs, essentially valuing the QF generation
11 at AURORA's estimate of future market prices with customers
12 taking all of the price risk. Under the proposed
13 methodology, the QF generation does not support surplus
14 sales , it is simply valued at the highest displaceable
15 incremental cost Idaho Power is incurring during the hour.
16 Thus, the proposed change focuses on determining the
17 incremental costs that can be avoided by the addition of QF
18 generation, and better aligns with the definition of
19 avoided cost.
20 Under Idaho Power's current implementation of the
21 IRP methodology, the QF receives a guaranteed contract
22 price based on AURORA's estimation of future market prices.
23 This eliminates the QF's risks with respect to future power
24 market prices for the duration of the contract, and Idaho
25 Power's customers have taken on the risk that the value of
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Idaho Power Company
1 the generation received from the QF will differ from the
2 QF's contract price. The Company's proposed change to
3 determine the incremental cost during each hour is a much
4 better estimation of the costs the utility is capable of
5 avoiding by taking the QF generation, and comports with the
6 federal requirements, without shifting all of the future
7 market risk of the QF transaction onto Idaho Power's
8 customers.
9 AVOIDED COST OF CAACITY
10 Q.Please describe how the avoided cost of
11 capacity is determined.
12 A.The methodology for determining avoided cost
13 of capacity is the same as that used in Idaho Power's
14 current implementation of the IRP methodology as described
15 in Company witness Stokes' testimony.
16 Q.Does Idaho Power propose to use the same
17 inputs in the determination of the capacity component of
18 avoided cost?
19 A.No. Although the methodology for
20 determining the capacity component of avoided cost is the
21 same, Idaho Power proposes that the resource type used to
22 determine this component of avoided cost be changed from a
23 combined cycle combustion turbine ("CCCT") to a SCCT.
24 Idaho Power's need for capacity is driven by summertime
25 peak-hour loads, typically during the hours of 3: 00 p.m. to
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Idaho Power Company
1 7:00 p.m. in the month of July. Because a SCCT is
2 typically the lowest cost supply-side resource for this
3 type of service, the fixed cost of a SCCT is a much more
4 appropriate input to use for this purpose than those of a
5 CCCT. Just as the current methodology uses the fixed costs
6 of a CCCT taken directly from the Company's IRP analysis,
7 the Company proposes that the fixed costs of a large frame
8 industrial SCCT, taken directly from the Company's IRP
9 analysis be utilized for determining the capacity component
10 of avoided cost going forward.
11 As noted in Commission Staff comments on Idaho
12 Power's Application for Determination Regarding its Firm
13 Energy Sales Agreement with High Mesa Energy, LLC, Case No.
14 IPC-E-11-26, Staff compared the capacity factors for SCCT
15 and CCCT units included in the Company's 20-year resource
16 plan in its 2009 IRP. Staff reported that based on
17 modeling results from the IRP, the capacity factors of the
18 SCCTs ranged from 0 to 14 percent and the capacity factor
19 for Langley Gulch (a CCCT) ranged from 36 to 49 percent,
20 with a 20-year average of 49 percent. This illustrates the
21 fact that while the capital cost of a CCCT is higher, it
22 will dispatch more often because of its higher efficiency
23 (lower heat rate). The higher capital cost of a CCCT
24 "buys" improved efficiency, which results in lower dispatch
25 costs, and, subsequently, a higher annual capacity factor
BOKENKAP, DI 23
Idaho Power Company
1 than a SCCT. In summary, a CCCT has higher fixed costs and
2 lower variable costs, and a SCCT has lower fixed costs and
3 higher variable costs.
4 Because the IRP methodology, as currently
5 implemented and as proposed by Idaho Power, includes both
6 capacity and energy components of avoided cost that are
7 determined independently, Idaho Power believes that it is
8 inappropriate to set the capacity component of avoided cost
9 with the capital cost of a CCCT when its need for capacity
10 can be served by a SCCT. As currently proposed, the energy
11 component of avoided cost will be the same regardless of
12 the resource type used to determine the capacity component
13 of avoided cost. If a CCCT is used to set the avoided cost
14 of capacity, customers will not receive the benefits
15 associated with a CCCT's higher efficiency.
16 Q.Are you proposing to continue to use the
17 peak-hour capacity factor calculation that is currently
18 utilized?
19 A.Yes. Idaho Power proposes no changes to
20 this approach, which is described by Company witness
21 Stokes.
22 AURORA INPUTS/ASSUMTIONS
23 Q.Are there any other assumptions or modeling
24 details associated with the proposed changes to the IRP
25 methodology that should be discussed?
BOKENKAP, DI 24
Idaho Power Company
1 A.Yes. Idaho Power's proposed change to the
2 IRP methodology focuses on determining the incremental
3 costs to an electric utility of electric energy which, but
4 for the purchase from the QF, such utility would generate
5 itself or purchase from another source. During many hours
6 of the year, Idaho Power's highest displaceable incremental
7 cost will be set by one of its thermal resources. And
8 because a thermal plant's heat rate changes with load, the
9 incremental costs also change with load. However, to
10 simplify the analysis, Idaho Power proposes use of the
11 following assumptions:
12 1.Each thermal unit is assigned one
13 incremental cost, which will be based on full load
14 operation, which applies all year long regardless of the
15 loading level determined in the AURORA analysis;
16 2.The incremental cost for each thermal
17 uni t is updated each year based on the fuel forecasts used
18 in the AURORA analysis; and
19 3.Once the highest displaceable
20 incremental cost is identified for a given hour, any amount
21 of displacement available from that resource (generator,
22 longer-term firm purchase or market purchase) sets the
23 incremental cost for that hour regardless of the volume
24 actually available to be displaceable; e. g., if there are
25 no purchases, and all thermal plants are either off or at
BOKENKAP, DI 25
Idaho Power Company
1 their minimums except for one Bridger unit which is at 10
2 MW above minimum and its incremental cost is $17 /MWh, then
3 the incremental cost for that hour is $17 /MWh even if the
4 "new" QF that the analysis is being run for is expected to
5 produce 20 MW during that hour. This simplification may
6 introduce some error, but it will always be in favor of the
7 QF since Idaho Power begins with the highest incremental
8 cost resource that is displaceable to set the avoided cost
9 for any hour.
10 Q.Do you have an exhibit that illustrates these
11 concepts?
12 A.Yes, these concepts are illustrated in Exhibit
13 No.7. There are six pages to this Exhibit.
14 Q.Will you please explain the purpose of each of
15 the six pages in Exhibit No.7?
16 A.Yes. Because the details of any avoided cost
17 model at this level of detail can be quite complex and
18 somewhat confusing, I have provided an example that
19 illustrates a number of the details. At a high level, the
20 first four pages of Exhibit No. 7 illustrate the type of
21 data that will either be input to or output from the AURORA
22 model. The last two pages of Exhibit No. 7 are the results
23 of calculations used to determine the hourly incremental
24 cost. This exhibit illustrates how a spreadsheet can be
25 used to calculate an hourly incremental cost.
BOKENKAP, DI 26
Idaho Power Company
1 Page 1 of 6 illustrates the output from AURORA that
2 is used by Idaho Power's proposed methodology to determine
3 the hourly incremental cost. The hourly loading of each
4 coal-fired and gas-fired unit is required, the hourly
5 quantity of longer-term firm purchases and the AURORA-
6 determined quantity of market purchases as well as the
7 AURORA-determined market clearing price are also required.
8 This information is largely used to determine which
9 resource has room to be displaced.
10 Page 2 of 6 illustrates the thermal resource data
11 used to set Idaho Power's minimum load levels and the heat
12 rates used in the determination of each resource's annual
13 incremental cost.
14 Page 3 of 6 illustrates fuel costs used in the
15 determination of each resource's annual incremental cost.
16 Page 4 of 6 illustrates the variable O&M costs used
17 in the determination of each resource's annual incremental
18 cost, and it identifies the escalation rate used to
19 escalate variable O&M costs.
20 Page 5 of 6 illustrates the results of calculations
21 to determine the annual incremental costs that are used in
22 each year to determine the hourly incremental cost. The
23 calculation is as follows: incremental cost (heat rate
24 (MMBtu/MWh) x delivered fuel cost ($/MMBtu) J + variable O&M
25 cost ($/MWh). The input data for heat rate is shown in
BOKENKAP, DI 27
Idaho Power Company
1 Btu/kWh; the units are converted to MMBtu/MWh as follows:
2 MMBtu/MWh = (Btu/kWh) x (1 MMBtu/1, 000, 000 Btu) x (1,000
3 kWh/1 MWh) .
4 Page 6 of 6 illustrates the result of calculations
5 to determine the hourly incremental cost. First, the
6 thermal resources on-line with displaceable capacity are
7 identified by subtracting the hourly loading from the
8 minimum loading - this occurs under the area labeled
9 "Determine Displaceable Quantity (MW)." Next, under the
10 area labeled "Determine Highest Displaceable Incremental
11 Cost ($/MWh)" for each resource that has displaceable
12 capacity, the incremental cost of that resource as
13 determined on page 5 of 6 is listed. If the displaceable
14 quantity is zero, then a zero is entered in this section.
15 For longer-term firm purchases and market purchases, if the
16 quantity of either is zero in an hour, then a zero is
17 entered; if either is non-zero in an hour, then the market
18 clearing price is entered. The hourly incremental cost is
19 determined by taking the maximum of the values listed under
20 the area labeled "Determine Highest Displaceable
21 Incremental Cost ($/MWh)."
22 QF QUEUING PROCESS
23 Q.Does Idaho Power have any other proposed
24 changes to the current implementation of the IRP
25 methodology?
BOKENKAP, DI 28
Idaho Power Company
1 A.Yes. Idaho Power proposes that any QFs with
2 signed contracts and any "queued" QFs be included in Idaho
3 Power's resource portfolio for purposes of calculating
4 future avoided costs because they can impact future avoided
5 costs. For purposes of calculating avoided costs, Idaho
6 Power proposes that upon its receipt of a written request
7 from a QF for contract pricing, the QF is designated as
8 "queued. "
9 As stated earlier, Idaho Power's resource portfolio,
10 for purposes of calculating a future avoided cost, can
11 change whenever a QF project enters the queue if that QF is
12 considered part of the resource portfolio. If "queued" QFs
13 and QFs with signed contracts are considered to be part of
14 the resource portfolio, then the calculated avoided cost of
15 energy and capacity can change for each new QF as a result
16 of the total amount of capacity and energy provided by all
17 proj ects in Idaho Power's portfolio. These changes are not
18 currently reflected in the avoided cost determination from
19 the current methodologies - be it the SAR or the present
20 implementation of the IRP-based methodology - which does
21 not change with the incremental addition of more QF
22 generation. Federal regulations allow for the individual
23 and aggregate value of energy and capacity from QFs on the
24 utility's system to be taken into account when determining
25 avoided cost rates for purchases from QFs. 18 C. F. R. §
BOKENKAP, DI 29
Idaho Power Company
1 292.304. This must be taken into account if avoided cost
2 is to be determined properly.
3 Q.Could you please explain?
4 A.Idaho Power's resource portfolio, for
5 purposes of calculating its future avoided cost, can change
6 whenever a new QF proj ect enters the queue if that QF is
7 considered to be part of the resource portfolio. For
8 example, if all QFs with contracts are on-line, and there
9 are no QFs in the queue, an analysis to determine the time
10 series of Idaho Power's avoided costs for use in pricing a
11 QF contract will produce a certain result. However, if
12 there are five 20 MW QFs in the queue and they are likely
13 to be built with the next few years, then Idaho Power is
14 proposing they be included in subsequent analyses to
15 determine Idaho Power's avoided costs for use in QF
16 contract pricing because they could have a direct impact on
17 calculations of Idaho Power's future avoided costs.
18 Q.What is the significance of including all QF
19 projects, in the aggregate, into the avoided cost
20 calculation?
21 A.The significance is that Idaho Power's avoided
22 costs change over time. As new resources, QF contracts, or
23 longer-term firm purchases are added to the resource
24 portfolio, Idaho Power's avoided cost can change. The
25 methodology used to calculate avoided costs needs to
BOKENKAP, DI 30
Idaho Power Company
1 consider changes in the resource portfolio and the
2 resul ting impacts on avoided cost. If changes to the
3 resource portfolio were limited to small changes, then
4 impacts would be minimal. However, Idaho Power has seen
5 large scale increases in the quantity of QF generation
6 under contract in a very short period of time. Significant
7 addi tions to Idaho Power's resource portfolio, such as the
8 very large amount of QF generation that has been added to
9 Idaho Power's system recently, can change Idaho Power's
10 avoided costs, and the methodology to determine avoided
11 cost must consider these changes.
12 Q.Do you have an exhibit that illustrates the
13 difference in QF contract rates developed using Idaho
14 Power's current implementation of the IRP methodology and
15 the methodology Idaho Power is proposing?
16 A.Yes.Exhibi t No. 8 provides an indication of
17 these differences for several different QF projects - a 20
18 MW baseload project, a 20 MW canal drop project, a 20 MW
19 fixed PV solar project, and a 22 MW wind project. These
20 are the same four proj ects that Idaho Power used to
21 illustrate its current approach for implementing the IRP
22 methodology, which was presented to the parties of this
23 case on December 15, 2011, in the Commission's hearing
24 room. A copy of that presentation is attached to Company
2 5 witness Stokes' testimony.
BOKENKAP, DI 31
Idaho Power Company
1 The proposed modifications to the IRP-based
2 methodology produce a lower avoided cost of energy for each
3 proj ect. This is expected because the proposed
4 modifications (which are based on identifying the
5 incremental costs to the utility for energy or capacity
6 which, but for the QF purchase, the utility would generate
7 itself or purchase) produce an avoided cost that is based
8 on the incremental cost avoided by displacing one of Idaho
9 Power's thermal generating resources, or avoiding a market
10 purchase. This is in contrast to the current
11 implementation of the IRP methodology which uses the QF
12 output to support market sales or displace purchases which
13 results in a market-based valuation as opposed to a
14 valuation based upon the definition of avoided cost.
15 The proposed modification to the type of resource
16 used in the avoided cost of capacity calculation results in
17 an avoided cost of capacity that is about 55 percent of
18 that produced by using a CCCT. This is also expected
19 because the capital costs of a SCCT are quite a bit less
20 than the capital costs of a CCCT. The total investment
21 costs for a SCCT and CCCT as identified in Idaho Power's
22 2011 IRP are $790/KW and $1,380/kW, respectively. Because
23 Idaho Power' s capacity needs are driven by summertime peak-
24 load hours, and because a SCCT is an appropriate resource
25
BOKENKAP, DI 32
Idaho Power Company
1 for this service, it reasonable to base the avoided cost of
2 capacity on a SCCT.
3 Q.Do you have any concluding remarks?
4 A.Yes. Idaho Power respectfully requests that
5 the Commission adopt the recommended changes to the IRP
6 methodology as set forth above. These changes align the
7 methodology to the definition of avoided cost from federal
8 regulations, and they help ensure that customers remain
9 indifferent as to whether the utility purchases energy from
10 a QF, or whether it generates the energy itself, or
11 purchases it from another source.
12 Q.Does this conclude your testimony?
13 A.Yes.
14
15
16
17
18
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20
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22
23
24
25
BOKENKAP, DI 33
Idaho Power Company
BEFORE THE
IDAHO PUBLIC UTiliTIES COMMISSION
CASE NO. GNR-E-11-03
IDAHO POWER COMPANY
BOKENKAMP, 01
TESTIMONY
EXHIBIT NO.7
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Thermal Resource Data
Used in 2011 IRP Aurora Analysis
Nameplate Ownership Minimum Mm. Load Full Load
Rating Share Load lPCo Share Heat Rate
Unit (MW)(%)(MW)(MW)(Btu/kWh)
Bridger 1 540 33%216 71 10,362
Bridger 2 540 33%216 72 10,389
Bridger3 540 33%216 72 10,439
Bridger4 540 33%203.4 68 10,340
Boardman 508.5 10%222.4 22 9,500
Valmyl 254 50%101.6 51 10,009
Valmy 2 267 50%105.8 53 10,147
Danskin 1 170 100%0 0 9,766
Danskin 2 49 100%0 0 11,358
Danskin 3 49 100%0 0 11,358
Bennett Mtn 170 100%0 0 10,100
Langley Gulch 314 100k 204 204 6,997
Exhibit No.7
Case No.GNR-E-11-03
K.Bokenkamp,PC
Page 2 of 6
PAGE 3 OF
EXHIBIT NO.7
CONTAINS
CONFIDENTIAL
INFORMATION
Exhibit No.7
Case No.GNR-E-11-03
K.Bokenkamp,IPC
Page 3 of 6
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PAGE 5 OF
EXHIBIT NO.7
CONTAINS
CONFIDENTIAL
INFORMATION
Exhibit No.7
Case No.GNR-E-11-03
K.Bokenkamp,PC
Page 5 of 6
PAGE 6 OF
EXHIBIT NO.7
CONTAINS
CONFIDENTIAL
INFORMATION
Exhibit No.7
Case No.GNR-E-11-03
K.Bokenkamp,PC
Page 6 of 6
BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
CASE NO.GNR-E-11-03
IDAHO POWER COMPANY
BOKENKAMP,DI
TESTIMONY
EXHIBIT NO.8
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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 KARL BOKENKAMP upon the following
named parties by the method indicated below:
Commission Staff X Hand Delivered
Donald L.Howell,II
____U.S.
Mail
Kristine A.Sasser
____Overnight
Mail
Deputy Attorneys General
____FAX
Idaho Public Utilities Commission X Email don.howell(puc.idaho.gov
472 West Washington (83702)kris.sasserpuc.idaho.gov
P.O.Box 83720
Boise,Idaho 83720-0074
Avista Corporation
____Hand
Delivered
Michael G.Andrea
____U.S.
Mail
Avista Corporation
____Overnight
Mail
1411 East Mission Avenue,MSC-23
____FAX
P.O.Box 3727 X Email michaeLandre©avistacorp.com
Spokane,Washington 99220-3727
PacifiCorp dibla Rocky Mountain Power
____Hand
Delivered
Daniel E.Solander
____U.S.
Mail
PacifiCorp d/b/a Rocky Mountain Power
____Overnight
Mail
201 South Main Street,Suite 2300
____FAX
Salt Lake City,Utah 84111 X Email [e-mail]
Kenneth Kaufmann
____Hand
Delivered
LOVINGER KAUFMANN,LLP
___U.S.
Mail
825 NE Multnomah,Suite 925
____Overnight
Mail
Portland,Oregon 97232
____FAX
X Email [e-mail]
Exergy Development,Grand View Solar II,
____Hand
Delivered
JR.Simplot,Northwest and Intermountain
____U.S.
Mail
Power Producers Coalition,Board of
____Overnight
Mail
Commissioners of Adams County,Idaho,
____FAX
and Clearwater Paper Corporation X Email petechardsonandcearycom
Peter J.Richardson qreq(richardsonandoleary.com
Gregory M.Adams
RICHARDSON &O’LEARY,PLLC
515 North 27th Street (83702)
P.O.Box 7218
Boise,Idaho 83707
CERTIFICATE OF SERVICE -1
Exergy Development Group
James Carkulis, Managing Member
Exergy Development Group of Idaho, LLC
802 West Bannock Street, Suite 1200
Boise, Idaho 83702
Grand View Solar II
Robert A. Paul
Grand View Solar II
15690 Vista Circle
Desert Hot Springs, California 92241
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
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
Board of Commissioners of Adams
County, Idaho
Bil Brown, Chair
Board of Commissioners of
Adams County, Idaho
P.O. Box 48
Council, Idaho 83612
Clearwater Paper Corporation
Marv Lewallen
Clearwater Paper Corporation
601 West Riverside Avenue, Suite 1100
Spokane, Washington 99201
CERTIFICATE OF SERVICE - 2
Hand Delivered
U.S. Mail
_ Overnight Mail
FAX
-2 Email jcarkulisCâexergydevelopment.com
Hand Delivered
U.S. Mail
_ Overnight Mail
FAX
-2 Email robertapaul08Câgmail.com
Hand Delivered
U.S. Mail
_ Overnight Mail
FAX
-2 Email don.sturtevantCâsimplot.com
Hand Delivered
U.S. Mail
_Overnight Mail
FAX
-2 Email rkahnCânippc.org
Hand Delivered
U.S. Mail
_ Overnight Mail
FAX
-2 Email bdbrown(ëfrontiernet.net
Hand Delivered
U.S. Mail
_ Overnight Mail
FAX
-2 Email marv.lewallen(ëclearwaterpaper.com
Renewable Energy Coalition
Thomas H. Nelson, Attorney
P.O. Box 1211
Welches, Oregon 97067-1211
Hand Delivered
U.S. Mail
_ Overnight Mail
FAX
-2 Email nelson(ëthneslon.com
John R. Lowe, Consultant
Renewable Energy Coalition
12050 SW Tremont Street
Portland, Oregon 97225
Hand Delivered
U.S. Mail
_ Overnight Mail
FAX
-2 Email jravenesanmarcos(ëyahoo.com
Dynamis Energy, LLC
Ronald L. Williams
WILLIAMS BRADBURY, P.C.
1015 West Hays Street
Boise, Idaho 83702
Hand Delivered
U.S. Mail
_ Overnight Mail
FAX
-2 Email ron(ëwilliamsbradbury.com
Wade Thomas, General Counsel
Dynamis Energy, LLC
776 East Riverside Drive, Suite 150
Eagle, Idaho 83616
Hand Delivered
U.S. Mail
_ Overnight Mail
FAX
-2 Email wthomas(ëdynamisenergy.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
-2 Email glenni(ëenvisionwind.com
margaret(ëenvisionwind .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
-2 Email greg(ëmimuralaw.com
Bil Piske, Manager
Interconnect Solar Development, LLC
1303 East Carter
Boise, Idaho 83706
Hand Delivered
U.S. Mail
_ Overnight Mail
FAX
-2 Email bilpiske(ëcableone.net
CERTIFICATE OF SERVICE - 3
Renewable Northwest Project
Dean J. Miler
McDEVITT & MILLER LLP
420 West Bannock Street (83702)
P.O. Box 2564
Boise, Idaho 83701
Megan Walseth Decker
Senior Staff Counsel
Renewable Northwest Project
917 SW Oak Street, Suite 303
Portland, Oregon 97205
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
Brian Olmstead, General Manager
Twin Falls Canal Company
P.O. Box 326
Twin Falls, Idaho 83303
Ted Diehl, General Manager
North Side Canal Company
921 North Lincoln Street
Jerome, Idaho 83338
Birch Power Company
Ted S. Sorenson, P.E.
Birch Power Company
5203 South 11 th East
Idaho Falls, Idaho 83404
Blue Ribbon Energy LLC
M. J. Humphries
Blue Ribbon Energy LLC
4515 South Ammon Road
Ammon, Idaho 83406
CERTIFICATE OF SERVICE - 4
Hand Delivered
U.S. Mail
_ Overnight Mail
FAX
-- Email joeCämcdevitt-miler.com
Hand Delivered
U.S. Mail
_ Overnight Mail
FAX
-. Email megancmrnp.org
Hand Delivered
U.S. Mail
_ Overnight Mail
FAX
-- Email smdcmidahowaters.com
Hand Delivered
U.S. Mail
_ Overnight Mail
FAX
-- Email olmsteadcmtfcanal.com
Hand Delivered
U.S. Mail
_ Overnight Mail
FAX
-- Email nscanaicmcableone.net
Hand Delivered
U.S. Mail
_ Overnight Mail
FAX
-- Email tedcmtsorenson.net
Hand Delivered
U.S. Mail
_ Overnight Mail
FAX
-- Email blueribbonenergycmgmail.com
Arron F. Jepson
Blue Ribbon Energy LLC
10660 South 540 East
Sandy, Utah 84070
Hand Delivered
U.S. Mail
_ Overnight Mail
FAX
-X Email arronesq~aol.com
Idaho Conservation League
Benjamin J. Otto
Idaho Conservation League
710 North Sixth Street (83702)
P.O. Box 844
Boise, Idaho 83701
Hand Delivered
U.S. Mail
_ Overnight Mail
FAX
-l Email botto~idahoconservation.org
Snake River Allance
Ken Miler
Clean Energy Program Director
Snake River Allance
350 North 9th Street #B61 0
P.O. Box 1731
Boise, Idaho 83701
Hand Delivered
U.S. Mail
_ Overnight Mail
FAX
-l Email kmiler~snakeriveralliance.org
· tlf7
Donovan E. Walker
CERTIFICATE OF SERVICE - 5
CERTIFICATE OF SERVICE
I HEREBY CERTIFY that on the 31st day of January 2012 I served a true and
correct copy of the CONFIDENTIAL PAGES OF EXHIBIT NO. 7 upon the following
named parties by the method indicated below, and addressed to the following:
Commission Staff
Kristine A. Sasser
Deputy Attorneys General
Idaho Public Utiities 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
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
RICHARDSON & O'LEARY, PLLC
515 North 2ih Street (83702)
P.O. Box 7218
Boise, Idaho 83707
Exergy Development Group
James Carkulis, Managing Member
Exergy Development Group of Idaho, LLC
802 West Bannock Street, Suite 1200
Boise, Idaho 83702
CERTIFICATE OF SERVICE-1
-l Hand Delivered
U.S. Mail
_ Overnight Mail
FAX
Email kris.sasserCipuc.idaho.gov
Hand Delivered
-l U.S. Mail
_ Overnight Mail
FAX
_Email michael.andreaCiavistacorp.com
Hand Delivered
-l U.S. Mail
_ Overnight Mail
FAX
_ Email daniel.solanderCipacificorp.com
Hand Delivered
-l U.S. Mail
_ Overnight Mail
FAX
Email peterCirichardsonandolearv.com
Hand Delivered
-l U.S. Mail
_ Overnight Mail
FAX
Email jcarkulisCiexergydevelopment.com
Grand View Solar II
Robert A. Paul
Grand View Solar II
15690 Vista Circle
Desert Hot Springs, California 92241
Renewable Energy Coalition
John R. Lowe, Consultant
Renewable Energy Coalition
12050 SW Tremont Street
Portland, Oregon 97225
Dynamis Energy, LLC
Ronald L. Willams
WILLIAMS BRADBURY, P.C.
1015 West Hays Street
Boise, Idaho 83702
Interconnect Solar Development, LLC
R. Greg Ferney
MIMURA LAW OFFICES, PLLC
2176 East Franklin Road, Suite 120
Meridian, Idaho 83642
Renewable Northwest Project
Dean J. Miler
McDEVITT & MILLER LLP
420 West Bannock Street (83702)
P.O. Box 2564
Boise, Idaho 83701
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
Brian Olmstead, General Manager
Twin Falls Canal Company
P.O. Box 326
Twin Falls, Idaho 83303
CERTIFICATE OF SERVICE - 2
Hand Delivered
-2 U.S. Mail
_ Overnight Mail
FAX
_Email robertapaul08Câgmail.com
Hand Delivered
-2 U.S. Mail
_ Overnight Mail
FAX
_ Email jravenesanmarcosCâyahoo.com
Hand Delivered
-2 U.S. Mail
_ Overnight Mail
FAX
_Email ron(cwilliamsbradbury.com
Hand Delivered
-2 U.S. Mail
_ Overnight Mail
FAX
Email greg(cmimuralaw.com
Hand Delivered
-2 U.S. Mail
_ Overnight Mail
FAX
Email joe(cmcdevitt-miler.com
Hand Delivered
-2 U.S. Mail
_ Overnight Mail
FAX
_ Email smd(cidahowaters.com
Hand Delivered
-2 U.S. Mail
_ Overnight Mail
FAX
Email olmstead(ctfcanal.com
Ted Diehl, General Manager
North Side Canal Company
921 North Lincoln Street
Jerome, Idaho 83338
Hand Delivered
-2 U.S. Mail
_ Overnight Mail
FAX
_ Email nscanalcacableone.net
Birch Power Company
Ted S. Sorenson, P.E.
Birch Power Company
5203 South 11 th East
Idaho Falls, Idaho 83404
Hand Delivered
-2 U.S. Mail
_ Overnight Mail
FAX
Email tedcatsorenson.net
Blue Ribbon Energy LLC
M. J. Humphries
Blue Ribbon Energy LLC
4515 South Ammon Road
Ammon, Idaho 83406
Hand Delivered
-2 U.S. Mail
_ Overnight Mail
FAX
Email blueribbonenergycagmail.com
Idaho Conservation League
Benjamin J. Otto
Idaho Conservation League
710 North Sixth Street (83702)
P.O. Box 844
Boise, Idaho 83701
Hand Delivered
-2 U.S. Mail
_ Overnight Mail
FAX
_ Email bottocaidahoconservation.org
Snake River Allance
Ken Miler
Clean Energy Program Director
Snake River Allance
350 North 9th Street #B61 0
P.O. Box 1731
Boise, Idaho 83701
Hand Delivered
-2 U.S. Mail
_ Overnight Mail
FAX
_ Email kmillercasnakeriverallance.org
Donovan E. Walker
CERTIFICATE OF SERVICE - 3