Rossdale 11 Repowering Project EPCOR Application #990289 Evidence of Optimum Energy Management Inc. Submitted on behalf of Central Area Council of Community Leagues Edmonton Federation of Community Leagues, October 1, 2000 Table of Contents 1 Executive Summary 3 2 Introduction 3 3 Issue #1 - Rossdale 11 Project is Not Efficient 5 3.1 Factors effecting plant efficiency 5 4 Issue #2 - Rossdale 11 has Transmission Disadvantages 6 4.1 Line Loss Charges 6 4.2 Location Based Credits 6 5 Unit NPV Cost Comparisons 7 5.1 Assumptions 8 General Assumptions 8 Economic Assumptions 8 Operating Cost Assumptions 8 Capital Cost Assumptions 8 Taxation Assumptions 9 5.2 Rossdale 11 9 Variable Operating Costs 9 Capital Costs 9 5.3 Greenfield Combined Cycle Gas Plant 9 Variable Operating Costs 10 Capital Costs 10 5.4 Co-generation Plant 10 Variable Operating Costs 10 Capital Costs 10 5.5 Methodology 11 6 Results 11 7 Other Issues 12 7.1 Rossdale and Bellamy Substations 12 8 Conclusions 12 9 Appendices 14 1 Executive Summary EPCOR claims that there is a geographic need for expanding the Rossdale facilities. In particular, EPCOR argues that the efficiency and economics of the proposed project are driven by its location at the Rossdale site. An economic analysis of the Rossdale Repowering project was conducted to test this claim. Based on capital cost and plant efficiency values quoted by EPCOR in their application, unit NPV costs of the project were determined and compared to two other comparable alternatives. The results of this analysis do not support EPCOR's claim regarding the geographic need for the proposed project. It can be demonstrated that EPCOR's proposed project has locational disadvantages compared to other possible projects. The use of the existing Rossdale 8 steam turbine in combined cycle with the proposed Rossdale 11 gas turbine reduces the overall efficiency of the proposed project and increases its operating costs relative to a greenfield combined cycle gas turbine (CCGT) utilising a newer steam turbine. In addition, operating costs are also increased by the location of the project on the AIES and the expected transmission charges that it will likely incur. The evidence contained herein submits that these disadvantages more than erode any capital cost advantage that the proposed Rossdale Repowering project may have. It is for these reasons that the economics supporting the location of the Rossdale 11 Repowering project cannot be justified. 2 Introduction The client, Central Area Council of Community Leagues and Edmonton Federation of Community Leagues, has retained Optimum Energy Management Inc. (OEMI) to produce this evidence. OEMI is a multi-disciplinary firm that provides energy management, emission management, training, supply, demand and price forecasting and generation development economic services to a host of clients. OEMI was formed in 1992 and currently employs 16 professionals. OEMI does participate in generation development projects. As an independent consulting firm, industrial customers and generation developers retain OEMI to help them evaluate potential projects. It is through this consulting practice that OEMI has obtained the skills and practical information on which this evidence is based. In its Memorandum of Decision with regards to EPCOR's application (Application No. 990289) the Board determined that it would consider in a hearing the "Need for expanded facilities at proposed location", but would limit its considerations to "siting issues and geographic need for the power plant"[1]. Hence, although the need for and economics of increased generating capacity in general is not within the scope of issues to be considered in a hearing, the need for and economics of expanded facilities at the Rossdale site is indeed within the scope of issues to be considered. It is within this context that OEMI submits this evidence. OEMI takes issue with EPCOR's claims that there is a geographic need for expanding facilities at the Rossdale site. In particular, OEMI disagrees with the following claims made by EPCOR in their application: The Rossdale Combined Cycle Plant is efficient[2] The Rossdale Combined Cycle Plant has transmission advantages[3] In general, EPCOR claims that the Rossdale Repowering Project will be economic. More importantly, they claim that much of this advantage is derived from the location of the proposed project[4]. EPCOR even goes as far as to suggest that it would be uneconomic to build new capacity in any location other than at the Rossdale site[5]. OEMI refutes these claims on the following basis: The efficiency of the Rossdale Combined Cycle Plant is not dependent on the site The Rossdale Combined Cycle Plant has transmission disadvantages compared to comparable projects located elsewhere on the AIES OEMI would therefore like to take this opportunity to present evidence that refutes the aforementioned claims made by EPCOR. Section 3 discusses the factors that effect the efficiency of a power plant and explains why the Rossdale Repowering Project is less efficient than comparable alternatives. Section 4 describes the current transmission charges faced by new generation projects and explains that, due to locational factors, the Rossdale Repowering Project has transmission disadvantages from a system- wide perspective. Based on the above factors, an economic analysis of the Rossdale Repowering Project was conducted and compared to the economics of two comparable alternatives. The methodology and assumptions underlying this analysis are presented in Section 5. In particular, the net present value (NPV) of unit costs for the Rossdale Repowering Project were calculated and compared to the unit NPV costs of two other generic alternatives: (1) a greenfield combined cycle plant located in the south and (2) a cogeneration project located in the north. The results of this analysis are discussed in Section 6. Section 7 3 Issue #1 - Rossdale 11 Project is Not Efficient Fuel costs tend to be the single largest cost of running a power plant. The efficiency of a power generation process refers to the amount of fuel (measured in units of heat energy) that is required to generate a unit of power. Hence, more efficient generation processes require less fuel to generate a unit of power and therefore have lower fuel costs. 3.1 Factors effecting plant efficiency The efficiency of a gas fired plant is a function of: The type of equipment used The ability to utilize waste heat from the gas turbine and the heat recovery boiler for other uses The elevation of the plant site Ambient air temperature The configuration of the plant, operational controls, etc. In general older steam turbines, such as the 40-year old Rossdale 8 unit, will tend to be less efficient than newer steam turbines utilising more recent technologies. The main reason for this is continuing improvements in steam turbine technology. In addition, older units will also be less efficient because of the overall wear and tear that comes with time. This degradation includes a greater potential for corrosion, leaks and cracking, which can all contribute to greater heat loss. Utilising the existing Rossdale 8 steam turbine in combined cycle with the proposed Rossdale 11 gas turbine reduces the efficiency of the entire combined cycle process below the efficiency that could be expected from a greenfield combined cycle plant. In general, higher efficiency plants have lower operating costs and therefore have a greater rate of cost recovery over time than lower efficiency plants like the Rossdale Repowering Project. The lower efficiency of the Rossdale Repowering project eliminates any of the capital cost advantages associated with utilising the existing Rossdale site and the existing steam turbine. 4 Issue #2 - Rossdale 11 has Transmission Disadvantages In the TA's 1999/2000 tariff application, an approach known as System Expansion Related Pricing (SERP) was proposed to send locational siting signals to generation developers. This approach consisted of a system of credits and debits based on the effect that the generator's location on the system had on the forecast constrained path decongestion costs. The signaling was designed to send efficient entry (new construction) and departure (decommissioning) signals. The signals provided in that application to Rossdale provided a 77% surcharge[6]. The effects of this signaling indicated that from a transmission system perspective that Rossdale was a poorer location for a generating station and that the economics of it's continued operation should be forced to overcome this surcharge. The full signalling effects of SERP were not adopted by the AEUB after significant lobbying by parties (including EPCOR) with vested interests in existing stations and prospective projects where a charge would accrue. As a result, only a system of credits was approved by the Board in Decision 2000-1 for incenting generators to valuable locations on the system. Nothing deters generators from locating in a poor part of the system and no signaling is provided to existing generators to shut down where the loss of that generator at its location (presuming it is replaced in the market by more suitable located generation) is a benefit to the transmission system by avoiding costly projects needed to relieve path constraints. Rossdale is such a location. 4.1 Line Loss Charges The transmission loss factors applicable to Rossdale remain somewhat in doubt, as the TA's methodology for deriving them is not expressly documented. Based on the best available information on the TA's methodology, OEMI has assumed that the factors applicable to the new gas turbine (Rossdale 11) will undoubtedly be different and in all likelihood higher than those applicable to the existing units. The TA methodology of deriving marginal loss factors based on the "last in MW" raises some concern about whether all of a re-powered Rossdale CCGT (8 plus 11) would be considered "last in" given that Rossdale 8 has left the system and return following re-powering. For modeling purposes a loss factor charge of 8% was used. 4.2 Location Based Credits Due the to transmission constraint on the bulk transmission system between Edmonton and Calgary, the TA determined that providing incentives for generation to be built around Calgary, may be a lower cost solution rather than to build new transmission capacity. An Invitation to Bid On Credits (IBOC) process was implemented by the TA where would-be generation developers were invited to submit a proposal to the TA for transmission capital cost deferral credits that would be paid over a 20 year period. The TA limited the credits to generation facilities located within 50 miles of Calgary and proposed credits up to 500 MW of capacity. In addition, the maximum amount of credits for any one party / consortium / plant was 200 MW. Recently, the TA awarded location-based credits to three generation projects in the Calgary area totalling 280 MW of new capacity. The credits rewarded in the IBOC process range from $3.25/MWh to $3.75/MWh[7]. With the IBOC process out of the way, the TA now intends to implement a Location Based Credit Standing Offer (LBC SO) process which (unlike the IBOC process) will continue on an on-going basis. The TA conducted a workshop on July 28 and September 8, 2000 to discuss the process for developing the LBC SO and presented a straw man outline of how such a process might work. The straw man was generally well received by those in attendance and is expected to be improved upon. EAL was ordered to file their LBC SO process with the AEB by September 15, 2000. The Rossdale Repowering project not only incurs the costs of transmission loss charges but it also incurs the opportunity costs of transmission credits that are forgone by not locating in Southern Alberta. For the purposes of modelling the costs of a generic CCGT located in the south, a $2/MWh credit is assumed. The transmission disadvantages of the Rossdale Repowering project (as reflected in the transmission loss charges that the project can be expected to incur as well as the opportunity costs of forgone transmission credits) eliminate the capital cost advantages associated with utilising the existing Rossdale site and the existing steam turbine. 5 Unit NPV Cost Comparisons EPCOR claims its Rossdale 11 repowering project has advantages over alternative projects due to the utilisation of a new large gas turbine and the incorporation of the existing Rossdale 8 Unit steam turbine and related equipment. With respect, in order to evaluate the overall benefit of the Rossdale site three key components need to be addressed: Variable operating costs (i.e. efficiency) Capital Costs Transmission related costs In order to test EPCOR's claims that Rossdale 11 developed at the Rossdale site is the best alternative, a comparison of the three key components were made for three generation projects: Rossdale 11 Developed at the Rossdale site A Greenfield combined-cycle plant located in southern Alberta A co-generation plant developed in conjunction with an industrial facility in northern Alberta For each, we have estimated costs and used assumptions that are indicative of similar projects being developed in Alberta of similar size to Rossdale 11. Since any forecast of expected revenues would be open to considerable debate, the analysis performed looks only at the costs each generation project would endure. 5.1 Assumptions The following assumptions were used for all three projects: 5.1.1 General Assumptions Project life - 2003 to 2020 Project size - 240 MW, 95% availability Inflation rate - 2.5% per year 5.1.2 Economic Assumptions Gas Price Forecast - rolling average of previous 30-day forward curves until 2004, OEMI long-run equilibrium forecast thereafter. Pool Price Forecast - assumed $45/MWh per hour flat, escalating at inflation (flat real, not real price increases. Since the pool price is only used to determine transmission loss charges, the accuracy of this forecast is not paramount to the evaluation. 5.1.3 Operating Cost Assumptions O& M Costs - $4/MWh to cover all variable and fixed O&M costs including plant labour, consumables, administration, overhead, etc. Escalated at rate of inflation. Transmission Related Costs - Proposed EAL filed transmission tafiff rates for 2001 were used for DTS and STS costs. Transmission loss factors under STS were from the TA's July 21, 2000 version for the years 2002 to 2005. It was further assumed that these loss factors would remain unchanged over the life of the facility. Back-up power - 5 MW of load required to start the plant (used to determine transmission charges). Assumed to be the same cost for all three scenarios. 5.1.4 Capital Cost Assumptions Interconnection costs - $11 MM (in year 1999 dollars) was included in the capital cost calculations for the generic CCGT and cogeneration plant to account for the costs of interconnecting at 240 kV. This estimate includes the costs of a generation substation, a 240 kV transmission line, and a 240 kV tap switching station. Any incremental transmission interconnection costs are assumed to be included in the Rossdale capital cost estimate quoted by EPCOR. Investor's discount rate (investor's return) - 14% Financing - a 50:50 debt/equity ratio was; equity portion of capital costs is paid in the first year of the project. This is indicative of financing for a merchant plant. Cost of debt - 9 % Repayment of principle - it is assumed that principle debt is repaid based on constant payments made every year. 5.1.5 Taxation Assumptions CCA - all plant machinery and equipment for the combined cycle processes used by the Rossdale Repowering project and the generic CCGT are treated as Class 1 capital and depreciated at 8%. Cogeneration plant and machinery are treated as Class 43.1 and depreciated at 30%. Interconnection capital costs are treated as Class 1 and depreciated at 4%. 5.2 Rossdale 11 The costs and assumptions used for the Rossdale 11 are taken primarily from EPCOR's application. 5.2.1 Variable Operating Costs The quoted efficiency of 47% was used to determine fuel costs[8]. 5.2.2 Capital Costs The quoted capital cost of Rossdale 11 is $115 MM (assumed in year 1999 dollars)[9]. 5.3 Greenfield Combined Cycle Gas Plant The generic combined cycle plant modelled consists of a gas turbine, heat recovery boiler, steam turbine and steam condenser. Hot exhaust gases from the gas turbine are ducted into a heat recover boiler, which produces high pressure steam. The steam is passed through a steam turbine and is then condensed back to liquid water. Both the gas turbine and the steam turbine drive electric generators. The variable and fixed cost assumptions used were taken from Gas Turbine World, an industry publication that lists relevant information for a number of different projects that have been developed around the world. Budgetary pricing levels ($/kW) and net plant efficiencies for Turnkey Combined Cycle Plants with comparable net output to Rossdale 11 Repowering project as quoted by Gas Turbine World 1999/2000 Handbook[10]. [pic] The average capacity of the plants quoted in the above strip is 243 MW (comparable to the output of the Rossdale Repowering project). It was assumed that the gas turbine contributed 60% of the available capacity (144 MW). The steam turbine was assumed to be about 96 MW. 5.3.1 Variable Operating Costs For combined cycle plants in the 240 MW range, the net plant efficiency averages about 54%. Since the comparison plant is to be located in Southern Alberta, the plant efficiency was reduced by 2% to account for the gas turbine operating at an elevation of about 925 meters above sea level. 5.3.2 Capital Costs The capital costs quoted from the publication were averaged and converted to $CDN at an exchange rate of $1.45 CDN / $1.00 US. In addition, a cost factor increase of 10% was added to reflect the fact that construction costs in Canada are somewhat higher than other parts of the world. These costs related primarily to the need for building enclosures in our colder climate. For the evaluation performed, a capital cost estimate of $172 MM (in year 1999 dollars) was used. 5.4 Co-generation Plant The generic co-generation plant modelled consists of a gas turbine and heat recovery boiler. Hot exhaust gases from the gas turbine are ducted into a heat recover boiler, which produces high pressure steam. The steam is then used in the industrial process either completely as in the case of steam assisted heavy oil recovery, or condensed in the industrial process and returned as liquid water. All electric generation is from the gas turbine driven generator. The economics of co-generation plants is complicated. The difficulty arises from what level of costs to allocate to the electric energy produced and what level to the steam energy produced. While there are many different formulas used in practice, the simplest is to use an opportunity cost approach for the steam energy. The steam energy costs were modelled based on the next best alternative - stand alone boilers. If the industrial process needs a certain amount of steam, they could produce this steam using boilers. The efficiency of the stand-alone boilers was assumed to be 85% at a capital cost of $32 MM (in 1999 dollars) The steam variable and fixed costs were then subtracted from the entire co- generation fixed and variable costs. The difference in these costs was assumed to be allocated to the electric energy production. 5.4.1 Variable Operating Costs For co-generation plants in the 240 MW range, the net plant efficiency allocated to electric energy production averages about 70%. This is significantly higher than combined cycle plants and demonstrates the advantages of using the steam directly in the industrial process. 5.4.2 Capital Costs The total capital costs for the generic cogeneration project were estimated to be about $192MM (in year 1999 dollars). From this, capital costs of $32MM were allocated to the production of steam energy. For the evaluation performed, a capital cost estimate of $160MM was used for electric energy generation. 5.5 Methodology Based on the aforementioned assumptions, per unit costs were estimated for the Rossdale project using capital costs and efficiencies quoted by EPCOR in their application. The analysis performed looks only at the costs each generation project would endure and does not attempt to forecast revenue. Operating cost calculations included initial capital outlays, transmission charges, O&M, back-up power costs and fuel costs. Transmission charges were calculated as a function of the plant location, while fuel costs were driven by plant efficiency. Since revenues are being ignored (i.e. revenue is assumed to be $0), taxes were applied to a negative amount of taxable "income" ($0 revenue less operating costs, interest payments on debt and CCA amounts). Taxes in this analysis are therefore treated as a credit and it can be assumed that there is an income stream to which this tax credit applies.[11] The resulting "taxes" were added to operating costs and any repayments on interest and principal during the period to arrive at a net cash cost outflow for every year until 2020. From this cash outflow, a net present value of costs was determined and divided by a net present value of expected output from each plant to determine a per unit cost estimate for the project. This was compared to costs estimated for a generic Greenfield CCGT located near major load in southern Alberta and a generic co-generation facility located in the north. 6 Results Since it is assumed that all three plants have the same output over the forecast period, differences in per unit cost estimates are driven entirely by the cost components for each type of plant. Results of this analysis are presented in the Appendices. While both the generic CCGT plant and co-generation facility have capital cost assumptions that were greater than the proposed Rossdale plant, both of these alternative projects displayed per unit cost estimates that were below that of the Rossdale plant. Cost differences between the generic CCGT and the Rossdale plant were driven primarily by the difference in line loss charges/credits. In particular, the line loss credit associated with the CCGT generated a cost offset of about $3 MM a year. The generic co-generation facility displayed unit costs that were also below those for the Rossdale plant primarily due to the greater efficiencies (and therefore lower fuel costs) associated with a co- generation process. In general, the higher efficiency projects allow for lower operating costs and a greater rate of cost recovery over time than lower efficiency plants. This analysis therefore shows that any capital cost advantages displayed by the Rossdale Repowering project are eliminated by its inefficiencies and locational disadvantages relative to alternative projects of comparable size. 7 Other Issues 7.1 Rossdale and Bellamy Substations EPCOR has cited the costs of moving existing power infrastructure from the Rossdale location as a reason for continuing operation of the Rossdale generation plant through repowering. EPCOR goes on to suggest that such costs would have to be borne by the company's customers and the City of Edmonton[12]. OEMI recognises that there are substantial costs involved in moving this infrastructure. In particular, OEMI feels the majority of these costs would be attributed to relocating the existing transmission and distribution infrastructure. Moving transformation points (i.e. the Rossdale and Bellamy substations) out of the river valley while maintaining the connectivity of the Edmonton downtown core 72,000 kV network would be very costly. OEMI expects this to be primarily due to the fact that a majority of the infrastructure required to maintain the connectivity of the transmission and distribution systems would likely have to be built underground, given the population density of the area, and would be a significant undertaking. OEMI submits, however, that these costs are not a necessary consequence of rejecting the Rossdale Repowering Project, as EPCOR appears to claim. More importantly, OEMI contends that keeping the aforementioned transmission and distribution infrastructure in its current location does not necessarily preclude reclamation of the majority of the land encompassed by the Rossdale site. If the Rossdale plant was decommissioned at the end of its useful life, the land currently used by those generating units (i.e. the High and Low pressure plants and supporting facilities) could be reclaimed. In addition, the majority of the Transformer Switch Yard, which steps up power generated from those units from 14,000 kV to 72,000 kV, would also be unnecessary. In order to keep Edmonton's downtown core connected with the Alberta Interconnected Electrical System, very few existing facilities would need to remain. Rossdale and Bellamy substations would be retained in order to continue to transmit power to the downtown core. As well, a small amount of switching (i.e. a 72,000 kV switch station) would also be needed to maintain connectivity with the downtown area. This would leave the majority of the Rossdale site available for reclamation. 8 Conclusions EPCOR claims that there is a geographic need for expanding the Rossdale facilities. In particular, EPCOR claims that the efficiency and economics of the proposed project are driven by its location at the Rossdale site. An economic analysis of the unit NPV costs of the Rossdale Repowering project compared to two other comparable alternatives does not support this claim. In fact, such an analysis illustrates that the Rossdale Repowering project has demonstrable disadvantages compared to other possible projects. This is due to the relative inefficiency of the Rossdale Repowering project compared to alternative projects and its transmission disadvantages. Reclamation of the majority of the existing Rossdale site is feasible without incurring large relocation expenses. If the Rossdale generation plant were decommissioned, the only facilities that would need to remain would be the substations and a small amount of switching. The rest of this land in the river valley could therefore be reclaimed. 9 Appendices I:\Rooney Prentice\Draft RD11 Report.doc 06/12/01 4:30 [pic] [pic] [pic] ----------------------- [1] EUB Memorandum of Decision, May 2000, page 18. [2] EUB Application No. 990289, Tab 1, s. 1.2: The Combined Cycle Plant will provide an economic and environmentally sound source of much needed additional generating capacity in the growing Alberta marketplace. After consideration of other site alternatives, the Rossdale location was chosen because: 1. There does not have to be a major investment in new infrastructure. 2. The Rossdale Unit 8 steam turbine-generator is in good condition and of ideal capacity for re-powering with one combustion turbine as a high efficiency combined cycle operation. 3. Rossdale's central location offers the potential for future efficiencies to be gained through district heating in central Edmonton (emphasis added) EUB Application No. 990289, Tab 4, s. 4.1.3: Plant Efficiency Unit 11, in combined cycle with existing Unit 8, will generate more than three times as much electricity as Unit 8 alone. The thermal efficiency will rise from about 26% to 47%. In other words about 45% less natural gas will be consumed to generate a kilowatt-hour of electricity. This increase in thermal efficiency will be achieved through two design features: 1. The Unit 11 gas turbine will be more thermally efficient on its own than the existing Unit 8. 2. The existing natural gas-fired boiler powering the Unit 8 steam turbine will be replaced with a heat recovery steam generator that will use waste heat from the gas turbine. 3. Unit 11 will not only generate more electricity at full load, but it will operate more continuously throughout the year due to its high efficiency. (emphasis added) Responses to supplementary IRs, BR-EPCOR2, p. 0106: Rossdale 11 (the proposed upgraded generator) is a state of the art combined cycle design which will improve thermal efficiency by nearly 80%. (emphasis added) [3] EUB Application No. 990289, Tab 1, s. 1.2: .the Rossdale location was chosen because: 1. .The transmission system is accessible on site with ample capacity to accommodate the new unit. No new transmission lines will be required 2. The Rossdale location places the new unit close to the downtown Edmonton load centre, increasing security of supply in an emergency to city customers and minimising transmission losses which increase emissions. (emphasis added) Responses to supplementary IRs, BR-EPCOR2, p. 0074: Importance of Rossdale Generation to the Downtown Load Center: 1. .With generation being in close proximity to the load, transmission losses are reduced and the efficiency of the overall transmission system is improved.(emphasis added) Responses to supplementary IRs, BR-EPCOR2, p. 0109: 1. .Without power generation close to the downtown load, a prohibitive investment in new transmission facilities would be needed to feed the downtown and to maintain an acceptable level of reliability. Power to downtown is fed through the Rossdale Substation. The Rossdale Substation is linked to the Bellamy Substation, which in turn is connected to a high voltage (240.000V) underground transmission line. Retirement of these facilities is not an option. Retirement of the Rossdale and Bellamy substations would require new transmission and distribution facilities to be built to supply the city's core. Such a project would be extremely disruptive to metropolitan Edmonton and area. (emphasis added) [4] EUB Application No. 990289, Tab 3, s. 3.1: The purpose of the Combined Cycle Plant is to add incremental generating capacity to the AIES, and to provide an economic source of energy from the repowering and continued operation of Rossdale Unit 8. (emphasis added [5] Responses to supplementary IRs, BR-EPCOR2, p. 0106: The site contains all the infrastructure and investment required to provide power generation, transmission and distribution, together with an important water treatment plant. It would cost up to $2 billion to move the power generation infrastructure alone. These costs would have to be borne by the company's customers, and the shareholder's asset base (the City of Edmonton) would lose significant value. [6] $2.97/MWh SERP charge plus the $3.82/MWh Interconnection Charge [7] EUB Decision 2000-47. [8] EUB Application No. 990289, Tab 3, s. 3.2.3. [9] Supplementary Information, Tab 4. [10] Gas Turbine World, Vol.20. [11] Assumes revenues are greater than costs to create taxable income. [12] Responses to supplementary IRs, BR-EPCOR2, p. 0106.