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Home My WebLink About20120419IPC to Staff 3-20.pdf1ECE PM Z: t lHO Q@PMWR@ An IDACORP Company DONOVAN E. WALKER Lead Counsel dwaIker(äidahoower.com April 19, 2012 VIA HAND DELIVERY Jean D. Jewell, Secretary Idaho Public Utilities Commission 472 West Washington Street Boise, Idaho 83702 Re: Case No. GNR-E-11-03 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 Dear Ms. Jewell: Enclosed for filing please find an original and three (3) copies of Idaho Power Company's Response to the Second Production Request of the Commission Staff ("Staff') to Idaho Power Company in the above matter. Also, enclosed in a separate envelope are four (4) copies of confidential information provided in response to Staff's Second Production Request. Please handle the confidential information in accordance with the Protective Agreement executed in this matter. Verytr lyyours, Donovan E. Walker DEW:csb Enclosures 1221 W. Idaho St. (83702) P.O. Box 70 Boise, ID 83707 DONOVAN E. WALKER (ISB No. 5921) JASON B. WILLIAMS (ISB No. 8718) Idaho Power Company 1221 West Idaho Street (83702) P.O. Box 70 Boise, Idaho 83707 Telephone: (208) 388-5317 Facsimile: (208) 388-6936 dwaIker(äidahoDower.com jwiIIiamsidahopower.com RECEIVED 2O2PR 19 PM 4: 46 ! ' f• UTILITIES COMMis1oN Attorneys for Idaho Power Company BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION IN THE MATTER OF THE COMMISSION'S REVIEW OF PURPA QF CONTRACT PROVISIONS INCLUDING THE SURROGATE AVOIDED RESOURCE (SAR) AND INTEGRATED RESOURCE PLANNING (IRP) METHODOLOGIES FOR CALCULATING PUBLISHED AVOIDED COST RATES. CASE NO. GNR-E-11-03 IDAHO POWER COMPANY'S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE COMMISSION STAFF TO IDAHO POWER COMPANY COMES NOW, Idaho Power Company ("Idaho Power" or "Company"), and in response to the Second Production Request of the Commission Staff to Idaho Power Company dated March 29, 2012, herewith submits the following information: IDAHO POWER COMPANY'S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE COMMISSION STAFF TO IDAHO POWER COMPANY -1 REQUEST NO. 3: In the direct testimony of Lisa Grow at page 12, lines 12-19, and at page 14, lines 15-17, and in the direct testimony of Mark Stokes beginning at page 44, line 14 and continuing to page 45, line 9, Idaho Power recommends that the Commission establish an authorized negotiation process and procedure by which Us can obtain power purchase agreements. However, neither Idaho Power witness proposes specific details of a process, procedure, or tariff. In the direct testimony of Rocky Mountain Power witness Paul Clements, beginning at page 2, line 17 and continuing to page 6, line 20, he proposes that the Commission adopt a new Tariff Schedule 38 for Rocky Mountain Power. Mr. Clements includes a draft of proposed Schedule 38 as Exhibit No. 202 to his testimony. Would Idaho Power support adoption for itself of a tariff similar to the draft Schedule 38 proposed by Rocky Mountain Power? If so, please identify and discuss any differences Idaho Power would propose for its own comparable tariff. RESPONSE TO REQUEST NO. 3: As indicated in the testimony of Lisa Grow and Mark Stokes and referenced by the Idaho Public Utilities Commission ("Commission") Staff in this production request, Idaho Power does recommend and will support the establishment of an authorized negotiation process and procedure by which qualifying facilities ("QF") can obtain power purchase agreements ("PPA") from Idaho Power. Idaho Power felt it was premature to include a draft of these proposed processes and procedures in its initial filings as Commission guidance and rulings in this case will most likely influence these processes and procedures. Idaho Power has reviewed the Schedule 38 provided in Mr. Clements's testimony as Exhibit No. 202 and agrees that this draft tariff appears to be a good initial draft of IDAHO POWER COMPANY'S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE COMMISSION STAFF TO IDAHO POWER COMPANY -2 these proposed procedures. In Idaho Power's review, it sees some areas that will need adjustment to reflect the final rulings in this case, some of those areas being: List of Required Information. The list of information required in Procedures, item 2 may need some minor changes and/or additions depending on the outcome of this case. For example, if Idaho Power's proposed alternative Integrated Resource Plan ("IRP") methodology is accepted, a key input to execute this pricing model is the hourly estimated generation of a proposed project for each hour of an entire year. Process for Negotiating Interconnection Agreement. Idaho Power will need to review this section and coordinate the processes with the Company's Schedule 72 (interconnection for QF projects). In addition, there is no information in this proposed schedule in regards to the interconnection requirements for off-system QF projects. As the case progresses, Idaho Power will be submitting a proposed tariff that will be similar to this proposed Schedule 38 and which will include the items listed above and any other modifications that reflect Commission guidance in this case. The response to this Request was prepared by M. Mark Stokes, Power Supply Planning Manager, Idaho Power Company, in consultation with Donovan E. Walker, Lead Counsel, Idaho Power Company. IDAHO POWER COMPANY'S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE COMMISSION STAFF TO IDAHO POWER COMPANY -3 REQUEST NO. 4: Idaho Power proposes that it be permitted to establish a new Schedule 74, which includes policies and procedures for operational dispatch of certain PURPA Qualifying Facilities, including curtailment during certain circumstances. If the Commission accepted the Company's proposal to adopt Schedule 74, would integration costs for intermittent QFs be affected? If so, has Idaho Power attempted to quantify the effect? Would Idaho Power propose to modify its currently authorized wind integration charge of $6.50 per MWh for intermittent wind generation? If so, how would Idaho Power propose to modify the $6.50 per MWh charge? RESPONSE TO REQUEST NO. 4: Idaho Power recently shared the results of its updated wind integration study at a public workshop on April 6, 2012. In this updated study, the Company has been careful to not include any costs associated with curtailment in the wind integration cost figures, and therefore would not compensate QF projects during periods where curtailment was necessary as outlined in Schedule 74. If Idaho Power were to compensate QF projects during periods of curtailment, the integration costs presented at the public workshop could be considerably higher depending on the amount of QF wind generation on Idaho Powers system. Idaho Power believes including curtailment costs in the wind integration cost and compensating QF projects for periods of curtailment would only serve to increase administrative burden as generation during periods of curtailment would have to be estimated for each individual QF project. Following a public and technical review process, Idaho Power may need to perform some additional modeling or other work related to the wind integration study. IDAHO POWER COMPANY'S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE COMMISSION STAFF TO IDAHO POWER COMPANY -4 Once complete, the Company intends to file the study with the Commission and request wind integration rates be updated to reflect the results of the study. The response to this Request was prepared by M. Mark Stokes, Power Supply Planning Manager, Idaho Power Company, in consultation with Donovan E. Walker, Lead Counsel, Idaho Power Company. IDAHO POWER COMPANY'S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE COMMISSION STAFF TO IDAHO POWER COMPANY -5 REQUEST NO. 5: The direct testimony of Tessia Park discusses generally the low loading conditions when the proposed Schedule 74 might require curtailment, and describes a representative example on pages 23-24. Has Idaho Power conducted any analysis or studies to attempt to estimate the frequency, duration, and magnitude of curtailments that might be invoked in the future or that would have been invoked in the past if its proposed Schedule 74 was in place? Please provide a copy of any analysis or studies. If no analysis or studies have been done, please provide estimates if possible. RESPONSE TO REQUEST NO. 5: Idaho Power has not conducted an analysis or study to estimate the frequency, duration, or magnitude of curtailments that might have been invoked or would be invoked in the future under the proposed Schedule 74. Idaho Power estimates that curtailments under Schedule 74 would occur during periods of low load and be more likely during high water conditions, such as in the spring months, and during periods of low market prices, which are indicative of there being no market demand for Idaho Power's surplus energy. As part of determining the hourly incremental cost in the alternate IRP methodology proposed in Company witness Bokenkamp's testimony, there are a small number of hours each year where the hourly incremental cost is zero. While these zero-cost hours are used in the calculation of the monthly average heavy load and light load price, they do not estimate the amount of curtailment expected under Schedule 74. During the zero-cost hours, Idaho Power would still be accepting delivery of QF generation, and paying the project the appropriate monthly average heavy or light load price. Similar conditions tend to exist (low load and high water) at times when the IDAHO POWER COMPANY'S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE COMMISSION STAFF TO IDAHO POWER COMPANY -6 hourly incremental price is zero and curtailment may be necessary under Schedule 74; however, they are not synonymous. The response to this Request was prepared by Tessia Park, Load Serving Operations Director, Idaho Power Company, in consultation with Donovan E. Walker, Lead Counsel, Idaho Power Company. IDAHO POWER COMPANY'S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE COMMISSION STAFF TO IDAHO POWER COMPANY -7 REQUEST NO. 6: If Idaho Power's proposed Schedule 74 were to be approved by the Commission and QFs were curtailed during certain low load conditions, would the avoided cost rates computed based on Aurora analysis be impacted? Has Idaho Power conducted any Aurora analysis to compute avoided cost rates under an assumption that QFs could be curtailed under certain low load conditions? RESPONSE TO REQUEST NO. 6: Avoided cost rates computed by AURORA are set for the duration of the contract based upon the QF's estimated hourly generation profile for a period of one year, and this computation is not impacted by possible curtailment. However, if Idaho Power must pay for curtailment, it must also be able to recover such payments. If Idaho Power may curtail without payment, no adjustment to avoided costs through the integration charge is necessary. In its updated wind integration study, the Company has been careful to not include any costs associated with curtailment in the wind integration cost analysis. The AURORA model used by Idaho Power to determine the avoided cost of energy is not capable of modeling wind curtailment and therefore curtailment is not valued in the pricing proposed by Idaho Power. Because a certain amount of curtailment is anticipated in the modeling performed as part of the wind integration study, Idaho Power does not believe it would be appropriate to account for curtailment in the avoided cost pricing model. The response to this Request was prepared by M. Mark Stokes, Power Supply Planning Manager, Idaho Power Company, in consultation with Donovan E. Walker, Lead Counsel, Idaho Power Company. IDAHO POWER COMPANY'S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE COMMISSION STAFF TO IDAHO POWER COMPANY -8 REQUEST NO. 7: Please provide a list of all QFs with approved PURPA contracts, and for each project list the following: 1) the project nameplate capacity, 2) whether the project has a generator output limit controls (GOLCs) installed, and 3) whether Idaho Power's proposed Schedule 74 would apply to the project. RESPONSE TO REQUEST NO. 7: It is Idaho Powers intention to apply Schedule 74 to QF Public Utility Regulatory Policies Act of 1978 ("PURPA") contracts with GOLC installed if their nameplate capacity is equal to or greater than 10 megawatts ("MW"). Please see the confidential list for specifics. The confidential list will be provided to those parties that have executed the Protective Agreement in this proceeding. The response to this Request was prepared by Tessia Park, Load Serving Operations Director, Idaho Power Company, in consultation with Donovan E. Walker, Lead Counsel, Idaho Power Company. IDAHO POWER COMPANY'S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE COMMISSION STAFF TO IDAHO POWER COMPANY -9 REQUEST NO. 8: If Schedule 74 is approved and a QF were curtailed, would Idaho Power propose to pay the QF for capacity or energy (either, neither, or both) during the period of curtailment? RESPONSE TO REQUEST NO. 8: No. Please see the Company's responses to Staff's Production Request Nos. 4 and 6. Because a certain amount of curtailment is anticipated in the modeling performed as part of the wind integration study, and no costs associated with curtailment are included in the wind integration charge, Idaho Power would not propose to pay for QF energy or capacity when curtailment was necessary for system reliability. The Company's proposed Schedule 74 is based directly upon Federal Energy Regulatory Commission regulations implementing PURPA. More precisely, Schedule 74 is based directly upon 18 C.F.R. § 292.304(f), which describes situations whereby utilities "will not be required to purchase electric energy or capacity during any period which, due to operation circumstances, purchases from qualifying facilities will result in costs greater than those which the utility would incur if it did not make such purchases, but instead generated an equivalent amount of energy itself." Under the operational circumstances describes in Schedule 74, and in the Direct Testimony of Tessia Park, Idaho Power's obligation to purchase energy and capacity from a QF does not exist; thus, there would be no payment during the period of curtailment. The response to this Request was prepared by M. Mark Stokes, Power Supply Planning Manager, Idaho Power Company, in consultation with Donovan E. Walker, Lead Counsel, Idaho Power Company. IDAHO POWER COMPANY'S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE COMMISSION STAFF TO IDAHO POWER COMPANY -10 REQUEST NO. 9: Idaho Power's proposed Schedule 74 does not address how non-QF long-term contractual power purchases will be handled in the event of curtailment. Please state the Company's proposed policy generally, and also specifically address all existing long-term power purchase agreements. RESPONSE TO REQUEST NO. 9: Idaho Power currently curtails its Elkhorn long-term, power purchase contract in the same manner as it does QF wind contracts in a pro rata method. Idaho Power does not expect to curtail the Elkhorn long-term PPA under the Schedule 74 curtailments because Schedule 74 does not apply to non-QF contracts. The response to this Request was prepared by Tessia Park, Load Serving Operations Director, Idaho Power Company, in consultation with Donovan E. Walker, Lead Counsel, Idaho Power Company. IDAHO POWER COMPANY'S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE COMMISSION STAFF TO IDAHO POWER COMPANY -11 REQUEST NO. 10: The avoided cost rates computed using an IRP methodology are typically presented in an FESA as monthly heavy and light load hour prices. If hourly prices are computed in Aurora, some of which may reflect a value of zero due to surplus conditions, how are these "zero value hours" captured and reflected in monthly prices contained in the FESA? RESPONSE TO REQUEST NO. 10: The average pricing that is a result of using the pricing methodology proposed in Mr. Karl Bokenkamp's testimony is calculated monthly for both heavy load and light load hours. The calculation being: 1.The project provided estimated energy for each hour is multiplied by the incremental cost for each hour to equal an estimated energy payment for that hour. 2.All hourly estimated energy payments ($s) and estimated energy deliveries (kilowatt-hours ("kWh")) are summed together for each month's heavy and light load hours. 3.The average $/kWh is then calculated by dividing the summed estimated energy payments by the summed estimated energy deliveries, keeping heavy and light load hours separate. As all hours are included in this average calculation, any hours in which the incremental cost is zero will result in the estimated energy payment for that hour being zero. However, if the estimated generation is not zero, the estimated generation will still be included in the denominator of this average calculation, thus reducing the total average energy price for that month. The response to this Request was prepared by M. Mark Stokes, Power Supply Planning Manager, Idaho Power Company, in consultation with Donovan E. Walker, Lead Counsel, Idaho Power Company. IDAHO POWER COMPANY'S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE COMMISSION STAFF TO IDAHO POWER COMPANY -12 REQUEST NO. 11: In the direct testimony of Mark Stokes at page 31, he discusses the calculation of the avoided cost of capacity in the IRP methodology. He states that the peak-hour capacity factor for wind, solar and canal drop projects is based on a 90 percent exceedance, but that for baseload resources (biomass, geothermal) peak-hour capacity factor is reduced from 100 percent to 92 percent to account for forced outages. Are forced outages also a possibility for wind, solar and canal drop projects? If so, does Idaho Power believe that the 90 percent exceedance values for wind, solar, and canal drop projects should be further reduced to account for the possibility of forced outages and to remain consistent with the treatment of baseload resources? RESPONSE TO REQUEST NO. 11: In calculating the 90 percent exceedance peak-hour capacity factor for wind and canal drop hydro, Idaho Power used actual production data; therefore, in theory, forced outages should be captured in these numbers. The 90 percent exceedance for these resources is consistent with the Company's IRP. The response to this Request was prepared by M. Mark Stokes, Power Supply Planning Manager, Idaho Power Company, in consultation with Donovan E. Walker, Lead Counsel, Idaho Power Company. IDAHO POWER COMPANY'S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE COMMISSION STAFF TO IDAHO POWER COMPANY -13 REQUEST NO. 12: In the direct testimony of Mark Stokes at page 34, he states that no carbon adder was used in the Aurora model to calculate the avoided cost of energy for the sample calculations. Recognizing that Idaho Power believes it would be inappropriate to include a carbon adder for avoided cost calculations, if a carbon adder consistent with assumptions used in the 2011 IRP were included in the sample calculations, what would be the result? RESPONSE TO REQUEST NO. 12: Using the IRP methodology described in the testimony of Company witness Mark Stokes, with the 2011 IRP carbon assumptions, the 20-year levelized avoided cost of energy for each of the four sample QF projects is as follows: baseload $63.57/megawatt-hour ("MWh"), canal drop hydro $60.90/MWh, fixed PV solar $62.00/MWh, and wind $56.16/MWh. The levelized prices for wind and fixed PV solar also include a $6.50/MWh deduction from the avoided cost of energy for integration costs. The response to this Request was prepared by M. Mark Stokes, Power Supply Planning Manager, Idaho Power Company, in consultation with Donovan E. Walker, Lead Counsel, Idaho Power Company. IDAHO POWER COMPANY'S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE COMMISSION STAFF TO IDAHO POWER COMPANY -14 REQUEST NO. 13: In the direct testimony of Mark Stokes beginning at page 39, line 24 and continuing to page 40, line 18, he points out that Langley Gulch will be dispatchable while QF resources are not dispatchable. In the IRP methodology as proposed by Idaho Power, is the lack of dispatchability of QF resources taken into account in computing an avoided cost rate? If so, can Idaho Power quantify the value of dispatchability? Please provide that value. RESPONSE TO REQUEST NO. 13: QF resources are not dispatchable and Idaho Power must take the energy as it is delivered by the QF. The table below presents the avoided cost of energy and capacity using the alternate IRP methodology proposed by Idaho Power in the testimony of Karl Bokenkamp. These avoided cost rates are based on the expected generation profile of each resource type: wind, solar, canal drop hydro, and baseload. QF Expected Generation Profile Avoided Cost of Energy (less applicable integration) Avoided cost of Capacity Total Wind Solar Canal Drop Baseload $35.86 $40.99 $45.45 $43.82 $0.82 $15.16 $18.18 $8.30 $36.68 $56.15 $63.64 $52.12 Capturing the full value of dispatchability is a difficult proposition; however, Idaho Power has attempted to quantify a portion of the benefit. In order to perform the avoided cost of energy calculation, the 20-year stream of Idaho Power's hourly incremental costs were sorted from highest to lowest and then QF generation was added to each hour, starting at the highest incremental cost hour. For each hour, the amount of generation was limited by the capacity of the resource. Generation was added for all the highest value hours until the total amount of energy was the same as the total energy provided by the project under the expected generation profile. The result of this process is an optimally dispatched resource, generating at its full capability IDAHO POWER COMPANY'S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE COMMISSION STAFF TO IDAHO POWER COMPANY -15 during the highest value hours throughout the 20-year contract term, valued at Idaho Power's incremental cost. This analysis hypothetically assumes that each resource is capable of generating during every hour of the year when, in fact, canal drop hydro projects only generate from April through October, solar PV projects are not able to generate at night, etc. For the avoided cost of capacity for a hypothetically dispatchable QF resource, the peak-hour capacity factor assumptions for each resource were changed. Wind, solar, and canal drop hydro were assigned the same forced outage rate as a simple- cycle combustion turbine (LSCCT), giving each of these resources a 95 percent peak- hour capacity factor. The baseload resource remained the same at 92 percent for both cases, which is based on a forced outage rate estimated by the Northwest Power and Conservation Council. All other assumptions/calculations for the avoided cost of capacity remained unchanged. The results of this analysis are presented in the table below: QF w/Optimal Generation Profile Molded Cost of Energy (no integration deduct) Molded Cost of Capacity Total Wind Solar Canal Drop Baseload $56.50 $59.79 $56.61 $45.49 $23.65 $35.87 $23.95 $8.30 $80.15 $95.66 $80.56 $53.79 Integration cost deductions were removed from the wind and solar avoided cost of energy because under the assumptions used, these resources would not be variable and intermittent, and would deliver energy in the highest value hours. The figures in the table below represent the differences in avoided costs between the expected QF generation profile and the optimally dispatched QF profile: IDAHO POWER COMPANY'S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE COMMISSION STAFF TO IDAHO POWER COMPANY -16 Difference Wind Solar Canal Drop Baseload Avoided Cost of Energy $20.64 $18.80 $11.16 $1.67 Molded Cost of Capacity $22.83 $20.71 $5.77 $0.00 Total $43.47 $39.51 $16.92 $1.67 Idaho Power believes the alternate IRP methodology it has proposed captures a portion of the value that is lost because QF resources are not dispatchable, but not the full difference. If a QF resource were truly dispatchable (in comparison to a utility operated natural gas plant), it could be economically dispatched and turned off when it is out-of-the-money or not needed to serve load. This simplified analysis and the required assumptions do not account for these differences. The response to this Request was prepared by M. Mark Stokes, Power Supply Planning Manager, Idaho Power Company, in consultation with Donovan E. Walker, Lead Counsel, Idaho Power Company. IDAHO POWER COMPANY'S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE COMMISSION STAFF TO IDAHO POWER COMPANY -17 REQUEST NO. 14: Idaho Power proposes that contract lengths be limited to five years, in part to relieve ratepayers of the risks associated with long-term contracts. Assuming facilities of equal capacity and 20-year contract lengths, please compare and contrast the risks associated with a) a QF, b) a utility-owned gas-fired project (such as Langley Gulch, and c) a non-indexed PPA (such as Elkhorn wind). Please compare the relative magnitude of the risks and identify who bears the risks—the utility, ratepayers, or project owners. RESPONSE TO REQUEST NO. 14: For a 20-year QF contract, ratepayers are taking all the risk associated with any variance from the avoided cost pricing level over the full term of the contract because the cost of QF contracts are passed directly to customers through the Power Cost Adjustment ("PCA") mechanism. The recent increase in QF projects Idaho Power has seen is an example of the magnitude of the risk customers bear when policy, practices, and pricing methodologies are not flexible enough to account for current conditions in the energy industry. Idaho Power believes its proposed application of the IRP methodology is a step in the right direction, but no one can be certain that all future conditions can be addressed by any of the pricing methodologies being proposed. Shortening the contract term to five years reduces the amount of time ratepayers would be exposed to the risk of changing conditions. QF developers argue they are either taking the risk associated with fuel expense (for a fueled project) or reducing ratepayer risk associated with fuel expense. However, as presented on page 16 of Company witness Stokes's testimony, ratepayers have not fared well over the last 10 years and are expected to continue to have to pay a premium for QF purchases over the next 10 years based on existing contract rates and forecast Mid-C prices. From page 19 of Company witness Stokes's testimony, this premium in IDAHO POWER COMPANY'S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE COMMISSION STAFF TO IDAHO POWER COMPANY -18 the cost of the energy is expected to average $67 million per year over the next 10 years. On the surface, it appears the risk to ratepayers is similar for QF contracts and non-indexed PPAs because prices would be fixed for the 20-year term of the agreement. However, a non-indexed PPA would be identified and scrutinized through the IRP process, re-evaluated through the Certificate for Public Convenience and Necessity process, and acquired through a competitive bidding process. All these steps ensure the size and type of resource being acquired are appropriate, competitively priced, and in the best interest of ratepayers. Once the PPA is signed, there is some risk associated with the prices being fixed for 20 years; however, the risk is substantially less than a QF contract because of the level of scrutiny that goes into the decision making process. For example, the Elkhorn wind contract is the only wind project in Idaho Powers resource portfolio that has been fully analyzed in the resource planning process and acquired through a competitive bidding process. None of the QF projects have ever been analyzed as part of the Idaho Power resource planning process nor have any of the Idaho Power QF contracts been acquired through a competitive bidding process. Under PURPA, utilities are obligated to sign QF contracts regardless of the type of resource, the timing of the energy deliveries, or whether there is a need. The recent influx of QF wind contracts Idaho Power has seen illustrates this point. For a long time, Idaho Powers need for additional resources has been driven by customers' peak-hour needs in the summer months. Because wind generation is variable and intermittent, it has the lowest peak-hour capacity factor (5 percent) of any resource option available and the 692 MW of nameplate PURPA wind Idaho Power has under contract will only IDAHO POWER COMPANY'S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE COMMISSION STAFF TO IDAHO POWER COMPANY -19 provide 35 MW of summertime capacity. If these QF wind projects had been subject to the same scrutiny as a non-indexed PPA, there would be no plausible basis for the Commission to approve them. However, the QF wind contracts were approved based on the PURPA policies and practices implemented in the state of Idaho with minimal opportunity for public or stakeholder involvement in the decision making process. In the case of a utility-owned, gas-fired project, ratepayers do take some risk associated with fuel cost; however, through hedging and other risk management practices, much of this risk is mitigated. If natural gas prices were to increase substantially, Idaho Power could consider buying in-ground gas reserves as a way to limit price volatility and high price risk. Idaho Power also works with a customer advisory group as part of its Risk Management Policy to minimize risk associated with fuel prices and market rates. Unfortunately, there is no similar group to assess the prudency of PURPA contracts. For any utility-owned resource, customers benefit substantially from a life cycle longer than 20 years. In the integrated resource planning process, most resources are assumed to have a 30-year life, but, in practice, are able to operate much longer. The Jim Bridger coal plant is currently in its 38th year of operation as the first unit came on- line in 1974. Many of Idaho Power's hydroelectric resources are much older, some nearly 100 years, and continue to produce low-cost energy. The response to this Request was prepared by M. Mark Stokes, Power Supply Planning Manager, Idaho Power Company, in consultation with Donovan E. Walker, Lead Counsel, Idaho Power Company. IDAHO POWER COMPANY'S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE COMMISSION STAFF TO IDAHO POWER COMPANY -20 REQUEST NO. 15: Please clarify whether it is Idaho Power's proposal that published rates for all resource types 100 kW and smaller be based exactly on the four sample project results presented in the direct testimony and exhibits of Mark Stokes. If not, does Idaho Power believe that any change in project characteristics or input data assumptions (e.g., fuel prices, load-resource balance, generation profile, project size, etc.) would be necessary before sets of published avoided cost rates could be determined that accurately represent Idaho Power's avoided costs? Please explain. RESPONSE TO REQUEST NO. 15: The published rates for the four sample projects contained in Mr. Stokes's testimony, Exhibit No. 3 beginning on page 21, were avoided cost prices calculated based on the IRP methodology in place as of December 15, 2012. This exhibit and the presentation on December 15, 2012, were intended to establish a baseline understanding of the application of the then prevailing use of the IRP methodology to calculate avoided costs for these sample projects. The attachments provided with this response present the calculated avoided costs for the same four sample projects using the proposed alternative IRP methodology and SCCT capital costs as proposed in the testimony of Company witness Bokenkamp, and a five-year contract term as proposed in Company witness Stokes's testimony (all other inputs; i.e., fuel prices, load-resource balance, generation profiles, etc., are the same as used in Exhibit No. 3 of Company witness Stokes's testimony). Under these assumptions, the avoided cost rates presented in the attachments would be representative of the published rates for the various resource types 100 kilowatts ("kW") or smaller. IDAHO POWER COMPANY'S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE COMMISSION STAFF TO IDAHO POWER COMPANY -21 For QF projects larger than 100 kW, Idaho Power is proposing to use a negotiated process for determining the appropriate avoided cost rates whereby the Company has the ability to update the IRP assumptions to account for changed conditions. This is an important point when considering where the "cap" should be set for access to published rates. Idaho Power believes a 100 kW cap is appropriate for all QF resource types as customers will be at risk from changed conditions during the two- year period between lRPs. If the IRP assumptions remain valid during the two-year period, published rates and negotiated rates will remain very close if not identical. If there are material changes in the proposed alternative IRP methodology or inputs at the conclusion of this case, Idaho Power would provide a final calculation of the published rates in compliance with the final ruling in this case. Idaho Power expects to have updated load forecast and natural gas price forecasts for the 2013 IRP available by the time this case is resolved, and would therefore expect to update the calculations at that time. The response to this Request was prepared by M. Mark Stokes, Power Supply Planning Manager, Idaho Power Company, in consultation with Donovan E. Walker, Lead Counsel, Idaho Power Company. IDAHO POWER COMPANY'S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE COMMISSION STAFF TO IDAHO POWER COMPANY -22 REQUEST NO. 16: Please clarify whether it is Idaho Power's proposal that published rates derived using the IRP methodology be adjusted for seasonality and heavy and light load hours similar to the methods currently applied to published rates, or whether hourly and seasonal adjustments would be based on Aurora analysis. For whichever method Idaho Power proposes, please provide, for each resource type, a complete schedule of proposed published rates that would be included in a FESA. RESPONSE TO REQUEST NO. 16: Idaho Power proposes to provide a unique monthly heavy load and light load price for every month for the full contract term. As these individual monthly prices are reflections of the actual value of the energy in each month, there will not be a need to apply the previously used seasonality factors. Please see the attachments provided in the Company's response to Staffs Production Request No. 15 for the actual proposed prices using the alternative IRP methodology. The response to this Request was prepared by M. Mark Stokes, Power Supply Planning Manager, Idaho Power Company, in consultation with Donovan E. Walker, Lead Counsel, Idaho Power Company. IDAHO POWER COMPANY'S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE COMMISSION STAFF TO IDAHO POWER COMPANY -23 REQUEST NO. 17: Avista in this case proposes, among other things, that the capacity and energy components of published rates be computed separately. The capacity value of a particular project would be based on its contribution during the utility's system peak hours. The capacity value, in turn, would then be spread over the hours the project is expected to operate during the year. One outcome of this approach is that the capacity value of project types with low annual capacity factors (such as canal hydro and solar) is spread over fewer hours, making rates for these project types much higher per MWh than for project types with high annual capacity factors (such as biomass and geothermal). Does Idaho Power agree with Avista's proposed approach for determining capacity value? If not, please explain why. RESPONSE TO REQUEST NO. 17: Idaho Power agrees that the described Avista Corporation ("Avista") process of calculating the avoided cost of capacity is similar to Idaho Power's proposed methods, which Idaho Power believes is an appropriate method to calculate the avoided cost of capacity. Idaho Power's proposed total avoided cost is made up of three distinct components: 1.Avoided Cost of Energy. This value is derived based on the incremental pricing concept being applied to the AURORA model's dispatch of Idaho Power's resources. 2.Avoided Cost of Capacity. This value is established as described in Exhibit No. 3 of Mark Stokes's testimony beginning on page 16 of that exhibit. 3.Integration Cost. This value is determined through integration studies. IDAHO POWER COMPANY'S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE COMMISSION STAFF TO IDAHO POWER COMPANY -24 In reviewing the Staffs Request and the Staff's provided summary of Avista's proposal of calculating avoided cost of capacity, Idaho Power believes its proposed methods are very similar. Avista proposes the avoided cost of capacity be based on the contribution during the utility's system peak hours. Idaho Power's process of calculating and applying the peak-hour capacity factor for a July day provides similar results. Avista proposes that the capacity value is then spread over the hours the project is expected to operate during the year. Idaho Power's process spreads the capacity value over the MWh of expected generation from the proposed project. In both cases, the avoided cost of capacity is paid for as part of the contract rate; therefore, capacity will not be paid for unless the project is generating electricity. The response to this Request was prepared by M. Mark Stokes, Power Supply Planning Manager, Idaho Power Company, in consultation with Donovan E. Walker, Lead Counsel, Idaho Power Company. IDAHO POWER COMPANY'S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE COMMISSION STAFF TO IDAHO POWER COMPANY -25 REQUEST NO. 18: In the direct testimony of Karl Bokenkamp beginning at page 12, line 21 and continuing to page 13, line 15, he states that Idaho Power is proposing to disregard the transaction-related costs and use the Aurora market clearing price to set the displaceable incremental cost for long-term firm, non-PURPA, power purchases whenever they are flowing. Please provide a reasonable estimate of any transaction- related cost (transmission costs, losses, etc.). RESPONSE TO REQUEST NO. 18: Transaction costs associated with reselling any of Idaho Power's longer-term firm purchases will depend on the location and timing of the purchases, and actual market conditions. There are several alternatives to consider: (1) resell at the point of purchase, (2) deliver the purchase to Idaho Power's system and then resell it at Idaho Power's border, (3) wheel the energy from Idaho Power's border to a more liquid market, or (4) wheel from the point of purchase to a more liquid market. Under alternative one, aside from employee time associated with the transaction, there are no additional transaction costs. Under alternative two, the transaction involves an allocation of costs associated with use of Idaho Power's point- to-point transmission (approximately $0.50/MWh) plus losses of 3.6 percent. Under alternative three, the transaction costs are those incurred under alternative two plus one or more wheels plus losses ranging from $1 .50/MWh and 1.9 percent losses to as much as $5/MWh and approximately 6 percent losses. Under alternative four, the costs could involve one or more wheels plus losses ranging from $1 .50/MWh and 1.9 percent losses to as much as $5/MWh and approximately 6 percent losses. As described above, there are a number of different alternatives that may come into play depending on the situation. The example for transmission costs and losses IDAHO POWER COMPANY'S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE COMMISSION STAFF TO IDAHO POWER COMPANY -26 used in Company witness Stokes's testimony on page 19, lines 19 and 20, is based on moving surplus energy from Idaho Power's system to the Mid-C market. For that estimate Idaho Power used $3/MWh for transmission costs plus $1 .50/MWh for transmission losses. In an overall average sense, Idaho Power believes that estimate is still representative. However, since Idaho Power's longer-term firm purchases have typically been for the purpose of serving summertime peak-hour loads, Idaho Power expects to be able to resell this energy at the point of purchase. In this case, transaction costs are de minimis. The response to this request was prepared by Karl Bokenkamp, Director of Operations Strategy, Idaho Power Company, in consultation with Donovan E. Walker, Lead Counsel, Idaho Power Company. IDAHO POWER COMPANY'S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE COMMISSION STAFF TO IDAHO POWER COMPANY -27 REQUEST NO. 19: Referencing again the testimony referred to in Request No. 18, please explain why Idaho Power would accept and pay for generation from a QF if, in order to be accommodated, it required that energy from a firm purchase be resold at market price. Explain why the value of energy from the QF would not be zero in any hour when a longer-term firm purchase would have to be sold to accommodate the purchase from the QF. RESPONSE TO REQUEST NO. 19: There are two reasons Idaho Power's proposed methodology for calculating the avoided cost of energy treats longer-term firm, non-PURPA power purchases as resources having a displaceable incremental cost equal to AURORA's market clearing price for that hour. The first reason is to maintain consistency with the logic Idaho Power has proposed for determining the highest displaceable incremental cost being incurred during each hour. While there are liquidated damages associated with either party's non-performance as described in more detail in Idaho Power's response to Exergy Development Group of Idaho Power's Request for Production No. 38(c), the damages are generally the differential between contract price and disposal or replacement cost, which is essentially the current market price. If Idaho Power paid $70/MWh for the longer-term firm purchase and market is $50/MWh, the differential ($20/MWh) is a sunk cost and the current value of the longer- term firm purchase is $50/MWh. Likewise, if Idaho Power paid $70/MWh for the longer- term firm purchase and market is $90/MWh, the differential ($20/MWh) is a benefit and the current value of the longer-term firm purchase is $90/MWh. Assuming the longer- term firm purchase can be resold at the current market price is the basis for using IDAHO POWER COMPANY'S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE COMMISSION STAFF TO IDAHO POWER COMPANY -28 AURORA's market clearing price for the displaceable incremental cost associated with that longer-term firm purchase. The second reason for assigning AURORA's market clearing price as the displaceable incremental cost for longer-term firm purchases is to prevent the perception that Idaho Power could "game" its proposed avoided cost methodology by entering into a large quantity of longer-term firm purchases, and thereby essentially remove the market purchase component of the proposed methodology. The response to this request was prepared by Karl Bokenkamp, Director of Operations Strategy, Idaho Power Company, in consultation with Donovan E. Walker, Lead Counsel, Idaho Power Company. IDAHO POWER COMPANY'S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE COMMISSION STAFF TO IDAHO POWER COMPANY -29 REQUEST NO. 20: Idaho Power proposes that the avoided cost of capacity be determined using a Simple Cycle Combustion Turbine (SCCT) rather than a Combined Cycle Combustion Turbine (CCCT). Please clarify whether it is the Company's proposal to use a SCCT as the basis for determining the avoided cost of capacity for all QF resource types. Does Idaho Power believe that it is equally appropriate to base capacity value on a SCCT for low capacity factor QF resources as for high capacity factor QF resources such as geothermal or biomass? Please explain. RESPONSE TO REQUEST NO. 20: The intent of Idaho Powers proposal to use an SCCT rather than a CCCT as the basis for the avoided cost of capacity was to use SCCT costs to determine the avoided cost of capacity for all QF resource types. In Idaho Power's 2011 IRP, the lowest cost portfolio included the Boardman to Hemingway transmission line. The next lowest cost portfolio, which was only slightly more expensive, contained SCCT resources and therefore would be the lowest cost supply- side resource option. Because of this, and considering avoided cost principles, Idaho Power believes it would be appropriate to use SCCT costs for determining the avoided cost of capacity for all QF resource types. The response to this Request was prepared by M. Mark Stokes, Power Supply Planning Manager, Idaho Power Company, in consultation with Donovan E. Walker, Lead Counsel, Idaho Power Company. DATED at Boise, Idaho, this 19th day of April 2012. DONOVAN E. WALKER Attorney for Idaho Power Company IDAHO POWER COMPANY'S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE COMMISSION STAFF TO IDAHO POWER COMPANY -30 CERTIFICATE OF SERVICE I HEREBY CERTIFY that on this 19" day of April 2012 I served a true and correct copy of IDAHO POWER COMPANY'S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE COMMISSION STAFF TO IDAHO POWER COMPANY upon the following named parties by the method indicated below, and addressed to the following: 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 dibla Rocky Mountain Power Daniel E. Solander PacifiCorp d/b/a Rocky Mountain Power 201 South Main Street, Suite 2300 Salt Lake City, Utah 84111 Exergy Development, Grand View Solar II, J.R. Simplot, Northwest and Intermountain Power Producers Coalition, Board of Commissioners of Adams County, Idaho, and Clearwater Paper Corporation Peter J. Richardson Gregory M. Adams RICHARDSON & O'LEARY, PLLC 515 North 27th Street (83702) P.O. Box 7218 Boise, Idaho 83707 Hand Delivered U.S. Mail Overnight Mail FAX X Email don.howelkpuc.idaho.cov kris.sasser(puc. idaho.qov Hand Delivered U.S. Mail Overnight Mail FAX X Email michael. and reaavistacorp.com Hand Delivered U.S. Mail Overnight Mail FAX X Email daniel.solander(pacificorp.com _Hand Delivered U.S. Mail _Overnight Mail FAX X Email petercrichardsonandoleary.com greq(richardsonandolearv.com IDAHO POWER COMPANY'S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE COMMISSION STAFF TO IDAHO POWER COMPANY -31 Exergy Development Group James Carkulis, Managing Member Exergy Development Group of Idaho, LLC 802 West Bannock Street, Suite 1200 Boise, Idaho 83702 Dr. Don Reading Ben Johnson Associates, Inc. 6070 Hill Road Boise, Idaho 83703 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 Bill Brown, Chair Board of Commissioners of Adams County, Idaho P.O. Box 48 Council, Idaho 83612 _Hand Delivered U.S. Mail —Overnight Mail FAX X Email jcarkulisexerqydeveIopment.com Hand Delivered U.S. Mail Overnight Mail FAX X Email dread inqmindsprinq.com Hand Delivered U.S. Mail Overnight Mail FAX X Email robertapauI08gmaiI.com Hand Delivered U.S. Mail Overnight Mail FAX X Email don. sturtevant(simpIot.com _Hand Delivered U.S. Mail _Overnight Mail FAX X Email rkahnnipDc.orq Hand Delivered U.S. Mail Overnight Mail FAX X Email bdbrownfrontiernet.net IDAHO POWER COMPANY'S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE COMMISSION STAFF TO IDAHO POWER COMPANY -32 Clearwater Paper Corporation Hand Delivered Mary Lewallen U.S. Mail Clearwater Paper Corporation Overnight Mail 601 West Riverside Avenue, Suite 1100 FAX Spokane, Washington 99201 X Email marv.IewalIenccIearwaterpaper.com Renewable Energy Coalition and Dynamis Energy, LLC Ronald L. Williams WILLIAMS BRADBURY, P.C. 1015 West Hays Street Boise, Idaho 83702 Renewable Energy Coalition John R. Lowe, Consultant Renewable Energy Coalition 12050 SW Tremont Street Portland, Oregon 97225 Dynamis Energy, LLC Wade Thomas, General Counsel Dynamis Energy, LLC 776 East Riverside Drive, Suite 150 Eagle, Idaho 83616 Interconnect Solar Development, LLC R. Greg Ferney MIMURA LAW OFFICES, PLLC 2176 East Franklin Road, Suite 120 Meridian, Idaho 83642 Bill Piske, Manager Interconnect Solar Development, LLC 1303 East Carter Boise, Idaho 83706 Renewable Northwest Project and Idaho Windfarms, LLC Dean J. Miller Chas. F. McDevitt McDEVITT & MILLER LLP 420 West Bannock Street (83702) P.O. Box 2564 Boise, Idaho 83701 Hand Delivered U.S. Mail Overnight Mail FAX X Email roncwiIIiamsbrad bury. com Hand Delivered U.S. Mail Overnight Mail FAX X Email i rave nesanmarcosvahoo.com Hand Delivered U.S. Mail Overnight Mail FAX X Email wthomas(ädynamisenerqy.com Hand Delivered U.S. Mail Overnight Mail FAX X Email qreqmimuralaw.com _Hand Delivered U.S. Mail _Overnight Mail FAX X Email biIIDiskeccabIeone.net Hand Delivered U.S. Mail Overnight Mail FAX X Email joemcdevitt-miIIer.com chascmcdevitt-miIler.com IDAHO POWER COMPANY'S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE COMMISSION STAFF TO IDAHO POWER COMPANY -33 Megan Walseth Decker Senior Staff Counsel Renewable Northwest Project 421 SW 6th Avenue, Suite 1125 Portland, Oregon 97204 Idaho Windfarms, LLC Glenn Ikemoto Margaret Rueger Idaho Windfarms, LLC 672 Blair Avenue Piedmont, California 94611 Twin Falls Canal Company and North Side Canal Company C. Thomas Arkoosh CAPITOL LAW GROUP, PLLC 205 North 10th Street, 4th Floor P.O. Box 2598 Boise, Idaho 83701-2598 Twin Falls Canal Company Brian Olmstead, General Manager Twin Falls Canal Company P.O. Box 326 Twin Falls, Idaho 83303 North Side Canal Company 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 11th East Idaho Falls, Idaho 83404 Blue Ribbon Energy LLC M. J. Humphries Blue Ribbon Energy LLC 4515 South Ammon Road Ammon, Idaho 83406 Hand Delivered U.S. Mail Overnight Mail FAX X Email megan(rnp.orq _Hand Delivered U.S. Mail _Overnight Mail FAX X Email glennicenvisionwind.com marqaretenvisionwind .com _Hand Delivered U.S. Mail _Overnight Mail FAX X Email tarkooshcapitolIawproup.com Hand Delivered U.S. Mail Overnight Mail FAX X Email oImsteadtfcanaI.com Hand Delivered U.S. Mail Overnight Mail FAX X Email nscanal(cabIeone.net _Hand Delivered U.S. Mail _Overnight Mail FAX X Email tedtsorenson.net Hand Delivered U.S. Mail Overnight Mail FAX X Email blueribbonenerciy(äcimaiI.com IDAHO POWER COMPANY'S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE COMMISSION STAFF TO IDAHO POWER COMPANY -34 Arron F. Jepson Blue Ribbon Energy LLC 10660 South 540 East Sandy, Utah 84070 Idaho Conservation League Benjamin J. Otto Idaho Conservation League 710 North Sixth Street (83702) P.O. Box 844 Boise, Idaho 83701 Snake River Alliance Ken Miller, Clean Energy Program Director Liz Woodruff, Executive Director Snake River Alliance 350 North 9th Street #13610 P.O. Box 1731 Boise, Idaho 83701 Energy Integrity Project Energy Integrity Project do Tauna Christensen 769 North 1100 East Shelley, Idaho 83274 Hand Delivered U.S. Mail Overnight Mail FAX X Email arronesgaol.com Hand Delivered U.S. Mail Overnight Mail FAX X Email botto(idahoconservation.orq Hand Delivered U.S. Mail Overnight Mail FAX X Email kmilIercsnakeriveralliance.orq Iwood ruffcsnakeriveralliance.orQ Hand Delivered U.S. Mail Overnight Mail FAX X Email taunaenerçyinteqrityproiect.orq /11 -T7 cN( 2ut& Christa Bearry, Legal Assistant IDAHO POWER COMPANY'S RESPONSE TO THE SECOND PRODUCTION REQUEST OF THE COMMISSION STAFF TO IDAHO POWER COMPANY -35 BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION CASE NO. GNR-E-11-03 IDAHO POWER COMPANY RESPONSE TO STAFF'S PRODUCTION REQUEST NO. 7 THIS ATTACHMENT IS xol~qA I 11:41LUM4 AND WILL BE PROVIDED TO THOSE PARTIES THAT HAVE SIGNED THE PROTECTIVE AGREEMENT BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION CASE NO. GNR-E-11-03 IDAHO POWER COMPANY RESPONSE TO STAFF'S PRODUCTION REQUEST NO. 15 Idaho Power Company Sample Wind Project Pricing Schedule 5 Year Contract Term MONTHLY ENERGY PRICES Mills per kWh Month/Year Heavy Load Purchase Price Light Load Purchase Price Jan-13 1-11.1 $25.96 $24.27 Feb-13 I. $24.82 $24.37 Mar-13 $23.97 $23.44 .....:.:..P!-13: $. 5 $21.56 5 4aY:1...3 $22.2.9 $1.5..3 . Jun-13 $22.18 $17.04 Jul-13 $34.13 $26.52 g-1 $39.80 . $•271.8. Sep-13 $30.43 $24.39 Oct-13 $30.39 $24.67 Nov-13 $33.32 $25.10 Dec-13 $31.79 $25.39 Jan-14 $27.61 $24.93 Feb-14 $26.04 $24.89 Mar-14 $25.36 $23.83 pr-i 4 .$273 $1..T4.8 - aY:.1..4. ....................................................... $2.2 1 .$1..3.86 Jun-14 $24.92 $19.39 Jul-14 $36.54 $27.51 Au.-14 $.42i7. .$•28.8.2 e.... $33.46 .$2.... Oct-14 $36.61 $26.26 Nov-14 $37.17 $27.38 Dec-14 $34.44 $26.56 Jan-1 5 $28.37 $26.40 Feb-15 $26.61 $26.12 Mar-15 $25.53 $24.24 Apr-.15 .$.24................................................................................................................ $.2.I.2•O Ma...5 .$•2.I.68 ..12.32 Jun-15 $25.74 $17.63 Jul-15 $41.74 $29.81 Aug-15 $46.75 $31.11 Sep-15 $35.32 _____ $26.73 Oct-15 $34.28 $26.71 Nov-15 $34.80 $27.07 Dec-15 $34.86 $27.18 Jan-16 $28.93 $26.58 Feb-16 $28.38 $26.33 Mar-16 $26.39 $25.60 Apr-I6 .$25.9.8 .$24.2. 6............................................................ $24:6.3 ......................................................................... $1..6.64............ ..... . ... ................ Jun-16 I. $26.48 $19.28 Jul-16 $44.04 $32.39 Au -16 .$4 .$32 .76 Sep-16 $40.89 $29.01 Oct-16 $38.63 $28.51 Nov-16 $39.91 $28.49 Dec-16 $38.47 $28.94 Jan-17 $31.50 $28.93 Feb-17 $30.28 $27.97 Mar-17 $28.47 $27.83 :1...7 . ....- .29- $.23.94...................................... rv!.a....7 .$26.76 .$15...53 . Jun-17 $29.51 $20.84 Jul-17 $45.64 $33.60 Au.-..1•7 .$5I..06 ......................34O.8 Sep-1 7 $40.70 $29.97 Oct-17 $43.56 $31.16 Nov-1 7 $43.09 $30.49 Dec-17 $39.64 $30.10 Idaho Power Company Sample Canal Drop Project Pricing Schedule 5 Year Contract Term MONTHLY ENERGY PRICES Mills per kWh Month/Year Heavy Load Purchase Price Light Load Purchase Price Jan-13 $0.00 $0.00 Feb-13 $0.00 $0.00 Mar-13 $0.00 $0.00 ..F!:1...3...... $3.0:35 $28:17........................ Mayl .3 .$2876 $22.00 . Jun-13 $28.71 .. $23.68 Jul-13 $40.59 . $33.31 Au.-13 $.46.2.3 $3.3.9 Sep-13 $36.77 $30.88 Oct-13 $36.92 $31.17 Nov-13 $0.00 $0.00 Dec-13 $0.00 $0.00 Jan-14 $0.00 $0.00 Feb-14 $0.00 $0.00 Mar-14 $0.00 $0.00 AP11 .. $.30 :2.6 $24..2.1................................................................... 4.. .......... . ... . ................................. .......... $23 $20:3 ........................................................ Jun-14 $31.54 $25.99 Jul-14 $43.01 $34.29 Au -..1 4 .$4&s... .:2 Sep-14 $39.88 $32.59 Oct-14 $43.19 $32.70 Nov-14 $0.00 $0.00 Dec-14 $0.00 $0.00 Jan-15 $0.00 $0.00 Feb-15 $0.00 $0.00 Mar-15 $0.00 $0.00 Apr-I .5 $3.0:64 $2..73 Ma 15................................. ....................... $28:2.. $1 .:°. Jun-15 $32.36 $24.57 Jul-15 $48.23 $36.73 Aug-is $53.24 $38.69 :-.-::..::..: . P i . $4. 1:5. 3. . _ 3. .?9 ._... . Oct-15 $41.01 $33.16 Nov-15 $0.00 $0.00 Dec-15 $0.00 $0.00 Jan-16 $0.00 $0.00 Feb-16 $0.00 $0.00 Mar-16 $0.00 $0.00 Apr -I 6 .$32.49 -.$30.84 ra .1!...... $311 I .$23.3.6 Jun-16 $33.08 $26.31 Jul-16 $74.26 $63.11 Au.g-.16 ..9.4.S $.87 eP-..16 ....0.3_ _..$59.4.S Oct-16 $69.06 $58.74 Nov-16 $0.00 $0.00 Dec-16 $0.00 $0.00 Jan-1 7 $0.00 $0.00 Feb-17 $0.00 $0.00 Mar-17 $0.00 $0.00 Apr-.17 .$.563 .4.27 Ma - ....7 .$.51.2- ................................................ . ....................46.i!.................................... Jun-17 $60.00 $51.51 Jul-17 $75.91 $64.37 Au.-..1 7 .$8.1:2.3. .$65.24........................................ SeP:1...7. .70 :90 .9.: ............................................................ Oct-17 $73.77 $61.54 Nov-17 $0.00 $0.00 Dec-17 $0.00 $0.00 Idaho Power Company Sample Baseload Project Pricing Schedule 5 Year Contract Term MONTHLY ENERGY PRICES Mills per kWh Month/Year Heavy Load Purchase Price Light Load Purchase Price Jan-13 $32.32 $30.75 Feb-13 $31.27 $30.81 Mar-13 $30.50 $29.98 AP13............................................................ $.....P.:3.5 .$2 Ma.............. ....... ........................... .................................................................. $28.7.. $2?0.9............................................................ Jun-13 $28.71 $23.68 Jul-13 $40.59 $33.31 -1...3. $46..23 $343.9 Sep-13 $36.77 $30.88 Oct-13 $36.92 $31.17 Nov-13 $39.70 $31.57 Dec-13 $38.04 $31.84 Jan-1 4 $33.84 $31.41 Feb-14 $32.51 $31.40 Mar-1 4 $31.85 $30.39 14 $30.26 Ma.y-1..4 $27.3 .$20.3.4. Jun-14 $31.54 $25.99 Jul-14 $43.01 $34.29 Au.:.I 4.................................... ......... . ............................................................... 45.8 $ ........ 36.2.6 Sep-14 $39.88 $32.59 Oct-14 $43.19 $32.70 Nov-14 $43.51 $34.03 Dec-14 $40.66 $32.99 Jan-15 $34.55 $32.87 Feb-15 $33.11 $32.64 Mar-15 $32.03 $30.84 •r-.15 $30.6.4 .$23. Ma.y-I...5 . 8 .20 .19.06 .. ........ Jun-15 $32.36 $24.57 Jul-15 $48.23 $36.73 Au.-..15 $.53.24 $8.6. Sep-1 5 $41 .53 $3320 Oct-15 $41.01 $33.16 Nov-IS $41.19 $33.60 Dec-IS $41.10 $33.62 Jan-16 $35.15 $33.02 Feb-16 $34.83 $32.83 Mar-16 $32.89 $32.13 AP!1! .$3 $30.84 6 .$.3.11 1 - $233.6 Jun-16 $33.08 $26.31 Jul-16 $60.83 $49.68 u..g-.16 $•60.2 5PA.4. SeP-................................................................ $.576.0 ..40.2 Oct-16 $55.63 $45.31 Nov-16 $56.66 $45.40 Dec-16 $55.07 $45.72 Jan-17 $48.07 $45.79 Feb-17 $47.14 $44.93 Mar-17 $45.38 $44.75 Apr-.1 7. 14a2.........___ $4.0.85. Ma.. 7 ............ $43.70 .$3?.:7.. Jun-17 $46.58 $38.09 Jul-17 $62.49 $50.95 Au..9:17. $67.81 ... $.5.1.8.2 Sep-17 $57.48 $46.98 Oct-17 $60.35 $48.12 Nov-17 $59.88 $47.44 Dec-17 $56.25 $46.95 Idaho Power Company Sample Solar Project Pricing Schedule 5 Year Contract Term MONTHLY ENERGY PRICES Mills per kWh Month/Year Heavy Load Purchase Price Light Load Purchase Price Jan-13 $25.23 $24.14 Feb-13 $24.58 $23.70 Mar-13 $24.02 $24.15 P..p.r-1.3 $2 I. . . 3:P.. ............... ..................... .. ... . ..... . ..... ............................................ .....$23 :9.. May:l.. $22.1.. $20 .95 Jun-13 $22.19 $18.71 Jul-13 $34.27 $32.53 U.:13 $.40.6I $36...3 Sep:13 $9:0.8 .$•24.24 Oct-13 $30.84 $26.31 Nov-13 $32.05 $24.24 Dec-13 $27.95 $24.86 Jan-14 $26.12 $25.14 Feb-14 $25.59 $25.14 Mar-14 $25.36 $24.76 r-i..4 $23.91 $22.09 !...a.Y:1..4 $•22 $13.32 Jun-14 $25.17 $20.29 Jul-14 $36.70 $33.12 Au.g-.1.4............................................................ .4•93 .$3.1. Sep-14 $33.53 $27.87 Oct-14 $37.40 $27.07 Nov-14 $35.66 $32.12 Dec-14 $30.08 $26.10 Jan-15 $26.63 $26.18 Feb-1 5 $26.48 $26.07 Mar-15 $25.54 $25.76 14.pr:lS $24:1 3 .$•2.1.42 MaY:15............................................................ $2.1 .82 .$1!:2..2 . ........ Jun-IS $25.83 $22.36 Jul-IS $42.06 9:l.....43 ..4?.:66 Sep-15 $34.63 $26.51 Oct-15 $35.35 $27.36 Nov-15 $33.49 $26.85 Dec-15 $30.85 $26.97 Jan-16 $27.15 $26.29 Feb-16 $27.98 $26.28 Mar-16 $26.32 $26.09 -16 $25.92 May-I6 .$2.4.6.. $•22.2. Jun-16 $26.57 $25.04 Jul-16 $64.09 $60.51 Au.g-16 .$69.8 -..........................................$6ai. Sep-16 $60.68 $52.29 Oct-16 $59.30 $49.15 Nov-16 $58.60 $49.62 Dec-I 6 $54.46 $49.44 Jan-17 $49.35 $48.67 Feb-17 $49.84 $48.35 Mar-17 $48.40 $48.26 ap1I7 _45:9 .................................... $43.87. May-1... _L4.°6 .$4.5. Jun-17 $49.64 $44.94 Jul-17 $65.73 $61.66 Au.9:17. $7.1..42 .$64:67 Sep-I 7 $60.52 $52.44 Oct-17 $63.11 $55.23 Nov-17 $62.04 $53.74 Dec-17 $54.76 $50.57