Economics of Renewable Generation in Estonian Electricity Market

Economics of Renewable Generation in Estonian Electricity Market Izabella Knõš, Mart Landsberg, Juhan Valtin Tallinn University of Technology, Elering AS, Estonian TSO izabella.knos@elering.ee, mart.landsberg@elering.ee Abstract- The primary objective of this analysis is to establish an up-to-date technical and economic data of new power plants in Estonia. To analyse if the recently made investments are profitable and how competitive they are to comprehend the private and public investors point of view. Keywords: Net Present Value (NPV); Internal Rate of Return (IRR); Generation Costs I. INTRODUCTION Economic progress requires continuous expansion of electricity generation, and energy sources become a strategic variable for sustain development. After deregulation, electricity companies have to deal with more risks, payback time, and rate of return on the investment, etc. The uncertainty of electricity prices a decade ahead, possible delays, regulatory changes, and general cash flows make it difficult for investors to commit to large-scale projects that might take 1 years or more to complete. During the last decade there has been an increasing focus on climate change, the emission of CO 2 and other greenhouse gases (GHG). The main option to reduce emissions is extensive introduction of renewable power generation. However, there is one current issue with most of the renewable technologies: they are still relatively expensive compared to conventional thermal solutions and without additional subsidies are not competitive in the market. By now, more than 6 countries have implemented some type of policy for renewables in electricity generation [1]. Additionally, part of this cost disadvantage is due to the fact that most conventional technologies have traditionally received- and continue to do so- significant direct and indirect subsidies [2]. Moreover, until recently, the full effect of the externalities, notably emissions of greenhouse gases, has not been reflected in prices. On the other hand there is growing concern about subsidies influence on countries economic development and rising energy costs -several countries in Europe have started to review current subsidy schemes and amounts. It is important for subsidies to be promoted for energy targets, but not too generous for investors. In this paper, the power plant investments and subsidies effect on private investor`s decision were valued using the Net Present Value (NPV) and Internal Rate of Return (IRR) methodology. The paper is organized as follows: in Section 2 the present situation was review in Estonia. Section 3 describes the concepts and methodology of calculations. In Section 4 the analysis of the results is presented. Finally, in Section 5 the conclusions are made. II. OVERVIEW OF PRESENT SITUATION Since the energy crisis in the 197s and later the growing concern for climate change in the 199s, policymakers at all levels of government and around the world have been enthusiastically supporting a wide range of incentive mechanisms for electricity from renewable energy sources. In the early 199s, promotional programs based on regulated and obligatory tariffs for the purchase of electricity from specified renewable sources became common and were refined in various European Union (EU) countries. The most important schemes fixed in tariff (FIT) and fixed premium systems used in Denmark, Germany and Spain gave the good effect [3]. More than 8% of EU wind generating capacity installed at the end of the 199s was located in these three countries. Estonia as a member of EU has prioritized an increase in the share of renewable energy. In order to promote the use of renewable energy sources, to make the energy sector more efficient and to ensure the security of domestic supply the subsidies were set in the Electricity Market Act of 23. The subsidies are paid for electricity which is generated by power plants with efficient technology of heat and power cogeneration (CHP) and from renewable sources. The subsidies consist of guaranteed fixed payments for produced kwh and it is included in electricity tariff, paid by consumers in proportion to their consumption of network services and the amount of electricity consumed. The main investments in power generation in Estonia have been made during years 1951-1978, after this only in early 2 the new investment in generation capacity was made. The growth of wind parks construction can be observed starting from 24. Today there is 259 MW of net installed capacity in Estonia, where around 17 MW of it are new wind parks and around 7 MW of it are new CHP [4]. Biomass provided the largest share of renewable energy in 211. In recent years, there has been an increasing interest in review of the existing scheme of subsidies for RES, as targets for 22 have been almost met. Currently, all new investments into new generation capacity are subsidized. There is a concern that Estonia is moving in the direction where the share of subsidies in electricity price is growing. The more subsidies are allocated to the production, the higher the price will be for consumers. Regardless of whether the produced electricity is sold in Estonia or exported, customers would have to pay subsidy of renewable electricity. Lately, there is a significant increase in the production of electricity from wind and biomass. At the same time, there are still not enough alternative sources of electricity production in a volume to be able to create 13

competition to the electricity production from oil shale. In 21, renewable electricity amounted to 9.7% of total consumption and 12% in 211. This means that Estonia will be very close to the goal of increasing the proportion of electricity to 15-2% produced from renewable sources by 22. The increase is mainly due to the utilization of biomass in oil shale boilers. It is important to construct such kind of power plants that are profitable in the conventional market conditions. Expansion of some green technology has occurred because of the considerable degree of policy-driven behaviour, rather than market driven behaviour. From the consumers' point of view, a more beneficial situation is when subsidies production at the same time reliable and competitive in an open electricity market as much as possible. The growth of renewable energy has been very fast in Estonia. Obviously, for a comprehensive investigation of the future development of RES technologies it is of crucial importance to provide a detailed investigation of the country-specific situation. This rapid growth equally shows the needs to overview the renewable energy subsidy system. III. CONCEPTS AND METHODOLOGY A. Cost of electricity generation The primary objective of this analysis is to establish an upto-date technical and economic data of new Estonian power plants and to investigate the attractiveness of investments into new generation capacity in Estonia with and without subsidies. Only the new power plants connected to transmission network during last 1 years were selected and the comparisons of its technical and economic data versus similar power plants in EU were compared. A base principle for collection the technical and economic data have been taken relying on public information [16, 17, 18], measured data as well as information provided by producers. The analysis focuses on the costs of electricity generation in 211. The calculation is based on the average unit cost approach. All calculations are based on real electricity, heat, fuel, environment prices in 211 and presented on a normalized basis, e.g. cost per MW, MWh or as annual expenses. This calculation requires two sets of inputs. The first set is specific to the power plant technology e.g. Operation and Maintenance (O&M) cost, fuel cost, environmental costs. The second set is related to the market including electricity, heat, CO 2 prices. The actual measured data of electricity and heat production in 211 were used for calculations of possible revenues from sales and producers average price. O&M costs are usually confidential information. Due to the difficulty to receive the actual power plants` expenses, the average statistical EU and US data for the same type of power plants were used [6, 7, 8] to estimate the annual fixed and variable costs. Additionally, the available information was used of annual financial reports (AFR) for comparison of calculated and actual profits and costs. The investment cost was provided by producers, all costs were recalculated for 211, taking into account annual average rate of inflation [9]. The amount of fuel consumption and prices were provided by producers. The average 211 price of CO 2 was used [1] and SO 2 and NO x prices that are set for environments costs calculations in the environmental tax law for 211 [11]. The results are shown in Table I Cost of Electricity Generation. TABLE I COST OF ELECTRICITY GENERATION Average 211 WP Average CHP, /MW 1 341 3 29 Average plant size, MW 2 22.5 Capacity utilisation factor, electricity % 27% 85% Average electricity production, MWh 46 51 167 Average heat production, MWh 329 Capacity utilisation factor heat, % 75% Lifetime, years 2 3 Construction time (months) 6-24 26 Profits Revenues from sales without, year 1 941 7 21 Revenues from sales with, year 4 439 15 25 Revenues from heat sales, /year 1 853 Costs O&M fixed costs (average EU), /MW/year 8 2 947 5 O&M fixed costs (US data), /MW/year 413 8 5 472 Variable costs (Danish data), /MWh/year 65 54 Fuel cost /year 1 36 Environment, /year 64 B. Valuation methodology; main indicators. Net Present Value (NPV) and Internal Rate of Return (IRR) In order to analyse the profitability of investment projects the Net Present Value method was used, NPV: T Ct NPV = + t t= (1 i) C where: t - time of the cash flow, i - discount rate, Ct- the net cash flow (the amount of cash, inflow minus outflow) at time t. C initial costs. NPV compares the value of money today to the value of that same money in the future, taking inflation and returns into account. If the NPV of a prospective project is positive, it should be accepted. However, if NPV is negative, the project should be rejected because cash flows will also be negative. One issue with decision making using the NPV is that the Cost of Capital is at best only an estimate and if it turns out to be different that the rate actually used in the calculation, and then NPV will be different. Provided that the NPV remains positive then the project will still be worthwhile, but if the NPV were to become negative that the wrong decision will have been made. In order to get estimation of efficiency of considered projects the Internal Rate of Return (IRR) for all projects was calculated. The IRR method is used to estimate the profitability of the plant. This method, which is also called the discounted cash flow method, measures the internal earning rate of an investment [12]. The discount rate often used in capital budgeting that makes the net present value of all cash flows from a particular project equal to zero. (1) 14

The two calculations were done for each type of power plant. First a pessimistic approach was used, where any changes in prices during the time were not taken into account and the value of production, revenue from electricity and heat sale, production costs remain constant over the fixed years of power plant lifetime. Second, the effect of possible changes of electricity, fuel, environmental prices was analysed and how they influence investment returns in sensitivity analysis. The investments returns were calculated with and without subsidies. Two types of power plants were considered: wind parks and medium heat and power cogeneration power plants. The fixed lifetime was taken: 2 years for wind parks and 3 years for medium-sized combined heat and power plants correspondingly. Unlike conventional power production, renewable electricity generation is intermittent and largely uncontrollable, since the weather or district heat supply conditions directly determine production. The constant expected yearly production was used for the investment analysis of all types of producers. Here it was assumed that production is sold on the spot market, so that the sale`s price completely determined by the electricity spot price, and the project fully bears the spot price risk. The calculation of annual producer s profit is based on real electricity and heat production data in 211 for corresponding producers and Nord Pool Spot EE area hourly electricity price and agreed heat prices in 211. It was assumed that the amount of profits production costs for each year during the whole period of investments return can be the same as in 211. The cost of balancing nor the grid reinforcing to accommodate new generation were not taken into account. As the profitability of many renewable electricity investments relies on the renewable energy support and in order to value the influence of subsidies on investments return the current support scheme was taken into account. The annual amount of received subsidies for corresponding producer is the same as in 211 1 for all 12 years. The possible changes of subsidy payments schemes were neglected. It was assumed that all the investment costs are incurred during the year before the plant starts generating. All calculations are done for the two discount rates 5% and 8%. C. Sensitivity analysis To verify the calculation results, additionally to the pessimistic approach, the sensitivity analysis was performed. Sensitivity analysis was proposed to investigate the impact of increasing electricity, heat and fuel prices as well as environmental taxes on investment returns. The increasing price of CO 2 was not taken into account. In order to estimate the growth of electricity prices in future, the study [19, 2] results were used. Based on the results for the reference case scenario the generation marginal costs in 225 will be 67.7 /MWh. The calculation of the average electricity prices gathered from the market by relevant power plants for 225 was received with the time series of hourly electricity prices and electricity production in 211. Based on the [2] study results and [4] information, it was assumed that there will be 9MW of Wind Parks and 1 Actual received amount of subsidies in 211 35MW of CHP in Estonia in 225. The linear interpolation method was used for the annual electricity prices calculation (Fig. 1). El price, /MWh 11. 95. 8. 65. 5. 9MW of wind energy by 216 Marginal Costs BAU225 A 18MW of wind energy by 216 Revenues from sales CHP Revenues from sales WP 35. 211 214 217 22 223 226 229 232 235 238 Fig. 1. The estimation of electricity price growth The calculated prices are shown in Table II. TABLE II ELECTRICITY PRICES IN 211 AND 225 Electricity price Average price WP CHP Diff WP Diff CHP 211, /MWh 43.35 41.73 43.12 1.61.23 225, /MWh 67.74 64.37 66.36 3.36 1.37 The biomass, peat and gas are the main fuels used by CHP s in Estonia. The fuel prices for reference year were taken from World Energy Outlook [5]. The forecast of fuels prices was based on analysis of historical data as well as on the data in [19, 2] analyses. The fuel prices for reference year are shown in Table III: TABLE III FUEL PRICES FOR REFERENCE YEAR Peat, (euro/gj) Biomass (euro/gj) Gas (euro/gj) 211 3.1 6.6 5.3 It has been assumed, that the growth of the heat prices will be connected the growth of the gas prices. According to the forecast, the gas prices will grow on average by 7% annually until 217, then growth will decrease up to 3% a year. The annual growth of peat prices by 5% and biomass prices by 1% in average can be expected up to 22 and after will decrease to 3% and 5% annually. The environmental costs for 5 years ahead were calculated; taking into account the concentration of SO 2 and NOx in the fuel and assuming the share and amount of used fuels will be the same. It was assumed that the same prices will be after 215. In this analysis the average CO 2 price in 211 was used, the increasing of CO 2 price was not taken into account. IV. RESULTS AND DISCUSSION D. Cost for generating electricity. Total 13 projects were considered, including 1 onshore wind parks and 3 CHP power plants. Almost 9% of these plants are owned by private investors and only 1% are owned by state. comprise 15

of land cost, construction, connection to the grid and all the necessary equipment for the plant operation. As it can be seen from the Table IV, the wind generation shows lower investment cost per MW (1,3 M /MW) than CHP (3,2 M /MW). The range of costs for onshore wind project is from 1,1 M /MW to 1,7 M /MW and the range of CHP investment costs is from 2,8 M /MW to 3,6 M /MW. Comparing to average EU data the investments cost in Estonia almost the same. The differences in costs depend on the cost of raw materials, labour, land, connection fees as well as location. The cost of wind turbine is dependent on materials that are likely to be in short supply (or pose constraints from extraction and processing perspective). This implies that the asset costs on a unit basis are likely to stabilize or not decrease too much in real terms. In future, increasing of the investment cost of Wind Park can be expected due to a limited access to the grid. Insufficient transmission grids for wind parks are potentially ones of the strongest barriers for reaching the target at lower costs. For example, the remote nature of offshore wind projects can lead to very intensive investment costs. TABLE IV INVESTMENT COSTS IN EU AND ESTONIA Investment cost Wind park CHP Danish, 21 1.4 M /MWh 1.3-1.9 M /MW EU average 1.1-1.5 M /MW 2.6-4.4 M /MW EE average, 211 1.3M /MW 3.2 M /MW Capacity utilization factor. The capacity utilization factor is the ratio, expressed as a percentage of the output electricity or heat production MWh to the power plant capacity MW. This factor refers to how much useful energy (electricity or heat) can be received. The average electricity utilization factor for wind parks is 27%. The utilization time of wind parks depends on the local wind resource, but also on the way the turbines are configured. The Danish average efficiency of on-land turbines lies in the interval of 22-35%. It was stated in [6] the larger and, thus, more expensive generator obviously generate more energy, but the utilization time is less. Thus, 15% more rotor area per MW yields about 12-13% more production per MW for a typical Danish site. For Danish wind turbines, the specific power has decreased substantially in recent years, ranging from about 42 W/m2 during 199-25 to about 35 W/m2 for modern turbines. The average heat utilization factor is 75% and the average electricity utilization factor is 85% for CHP. The combined heat and power plant accounting for 3% of generating capacity, used natural gas, peat and biomass, producing 57% of electricity in 211.The total efficiency equals the total electricity delivery plus heat divided by the fuel consumption. The average efficiency of the considered CHP is 76%. The relative competitiveness of CHP depends on heat demand or on the operation mode of the plant and heat- control mode. If the heat demand is constant over the entire year, e.g. in CHP plants used for industrial applications, the power utilization is stable with a low volatility. In other applications, such as CHP for district heating, heat demand follows the seasonal fluctuations and utilization is significantly lower. In this analysis all CHP considered are used for district heating. The average electricity and heat capacity utilization factors are presented below in Table V. TABLE V CHP EFFICIENCY IN EU AND ESTONIA 211 Efficiency electricity, % Efficiency heat, % EE average 27 49 EU average 22-27 63-66 Producers average price, gathered from the spot market. The actual measured data of electricity and heat production in 211 were used for calculations of possible revenues from sales and producers average price. The producers average price is the ratio of the received profit of electricity and heat sale of the amount of produced electricity and heat. The average electricity price is shown in Fig. 2. Wind power average price is 41.73 /MWh, it means that during windy periods, there is overproduction in the market and prices are lower than during windless periods. It means that wind park cannot deliver electricity at the best times. The average price of CHP is 43.12 /MWh, it is also a bit less than average market price which was 43.35 /MWh in 211. The difference will increase, as it can be seen from Table II, with increasing share of wind generation, decreasing at the same time the revenue from the sale. As it is known from energy market theory the marginal generators set the market price. The market price is, therefore, equal to the cost of producing the last MWh. While the marginal generator will not lose the money on the sale of the electrical energy it produces and it will not collect any economic profit either. The part of the revenue from sale must be used to cover the fixed costs of the plant. If the production costs of some power plant less than market price this utility never collects economic profits. Another issue is large-scale introduction of low marginal cost generation. With increasing share of wind power, the wholesale/spot prices decrease [13, 14, 15, 2]. Wind generation has the lowest marginal costs and it replaces fossil fuel generators with short term fuel and operating costs. Hence, the wholesale cost of electricity production is reduced. The price reduction in its turn means reduction in profits from sales and operation hours for other producers. On the other hand, reduction the wholesale/spot price does not always lead to benefits for consumers, this reduction can be approximately equivalent to the additional payments incurred through the subsidy levy. El price, EUR/MWh 12. 1. 8. 6. 4. 2.. 53.7 48.19 43.35 5.21 41.73 43.12 43.43 Wind parks Small CHP Large CHP Share of subsidies in producers price Producers average price without subsidies Average market price Linear (Average market price) Fig.2. The average producers electricity price in 211 16

Operation and maintenance costs. Due to the failure to receive the actual power plant expenses available average EU and US statistic data for the same type of power plants were used. The O&M are divided into two subcategories, fixed (are independent of how the plant is operated /MW) and variable O&M (are dependent of how the plant is operated /MWh) costs. In the [6], fixed costs included: administration, operational staff, property tax, insurance, and payments for O&M service agreements. Re-investments within the stated lifetime were also included. The variable O&M costs included: consumption of auxiliary materials (water, lubricants, and fuel additives), spare parts and repairs. In the [8] report O&M including maintenance expenses were given on an average basis. In order to estimate the accuracy of calculations the actual 21 data of selected power plants annual financial reports were compared with calculated data. The differences in the costs mainly depend on the cost of labour, operation time, age of power plant and environmental taxes. Using average wind park O&M data for US, the minimum production costs were received and with EU average the maximum costs were received. The low level of Estonian average actual costs in 21 can be explained by the fact that almost all considered wind parks are quit new (in operation since 28), but the increase of the annual costs can be expected in future. Based on the data of annual financial reports the main expenses related to maintenance and labour costs and as it can be seen in [6], main expenses Germany and Denmark also related to maintenance and labour costs. The O&M costs of Wind parks are shown in Fig. 3. MEUR 1..8.6.4.2. WP costs AFR average, 21 Calculation, US data Calculation, EU average Fig. 3 Operation and maintenance costs of Wind parks In case of CHP-s, the maintenance expenses depend on technology, overhauls, operating intervals as well as on number of outages. The maximum fixed and variable costs were selected for the maximum production costs calculation and minimum fixed and variable costs for minimum production costs calculation. With EU average data, the production costs of CHP-s were closer to the actual costs in 21. The minimum costs were received with Danish data and the maximum costs were received with US data. About 7% of total CHP costs are fuel costs. The biomass (54%), peat (11%) and gas (35%) are the main fuels used by CHP in Estonia. Wood is usually the most favourable biomass for combustion due to its low content of ash and nitrogen. Environmental policy will also play an increasingly important role that is likely to significantly influence the fuel costs in the future and the relative competitiveness of various generation technologies. The O&M costs of CHP are shown in Fig. 4. MEUR/year 15. 12. 9. 6. 3.. AFR average, 21 Calculation, US data Calculation, EU average Environment, /year 64,. 64,. Other costs, CHP 4,26,242.74 1,51,93.13 3,481,93.13 Fuel costs 1,74,193.34 1,36,. 1,36,. Fig. 4. Operation and maintenance costs of CHP Costs, CHP In this analysis the environmental costs for 5 years ahead were calculated, taking into account the concentration of CO 2, SO 2 and NOx in the fuel and assuming the share and amount of used fuels will be the same. From the environmental payments point of view the most costly fuel is peat, due to high concentration of CO 2, it makes 97% of total cost. The average data are presented below in Table VI. TABLE VI ENVIRONMENTAL COSTS Costs of CO 2, SO 2, NOx, /year Total 211 638437 Total 212 663288 Total 213 645325 Total 214 649671 Total 215 65485 E. Net Present Value (NPV) and Internal Rate of Return (IRR) An investor will finance production facility if the plant will earn a satisfactory profit over its lifetime. The results of calculation presented in chapter 3 were used to estimate the profitability and efficiency of made investments. Based on the results of the NPV as well as IRR calculation, the Wind Parks average project without subsidies are not profitable in both pessimistic and sensitivity analysis (Fig. 5 and 9). In sensitivity analysis positive NVP can be seen, only in case of minimum annual costs after 18 years of the plant operation. Since in this analysis the cost of balancing was not taken into account, it is clear that minimum annual cost will be higher. So it can be stated that without subsidies the average Wind Park in Estonia is not a profitable project. The NVP of average Wind Park with subsides becomes positive after 8 years in case of minimum annual costs and after 11 years if with the maximum annual costs (Fig. 6, 1). With subsidies the IRR of Wind Park project is 8-1 per cent and 12-14 per cent after 12 years of operation accordingly for pessimistic and sensitivity analysis (Table VII). The NVP of average project of CHP without subsidies becomes positive in case of minimum annual costs after 19 years in pessimistic analysis (Fig. 7) and profitable after 12 and 15 years in case of sensitivity analysis (Fig. 11). 17

3-7 2 4 6 8 1 12 14 16 18 1 5-5 -1 2 4 6 8 1 12 14 16 18 2-17 -15-2 -25-27 Fig. 5. NPV of average WP without subsidies -3 Fig. 9. Sensitivity analysis, NPV of average WP without subsidies 15 5, 4 3 2-5 -15 3 6 9 12 15 18 1-1 1 3 5 7 9 11 13 15 17 19 21-2 -25 Fig. 6. NPV of average WP with subsidies -3 Fig. 1. Sensitivity analysis, NPV of average WP with subsidies 3 2 1-1 -2-3 -4 2 4 6 8 1 12 14 16 18 2 22 24 26 28 3 16 12 8 4 1 3 5 7 9 11 13 15 17 19 21 23 25 27 29 31-5 -6-4 -7 Fig. 7. NPV of average CHP without subsidies -8 Fig. 11. Sensitivity analysis, NPV of average CHP without subsidies 1 8 6 22 17 4 2-2 -4 2 4 6 8 1 12 14 16 18 2 22 24 26 28 3 12 7 2-6 -8-3 2 4 6 8 1 12 14 16 18 2 22 24 26 28 3-1 Fig. 8. NPV of average CHP with subsidies -8 Fig. 12. Sensitivity analysis, NPV of average CHP with subsidies 18

TABLE VII INTERNAL RATE OF RETURN (IRR) OF THE AVERAGE WIND PARK AND CHP PROJECT IRR 12 years Pessimistic analysis, Sensitivity analysis Without max costs Without min costs With max costs With min costs WP -9% -5% 8% 1% CHP -7% % 12% 16% WP -5% -2% 12% 14% CHP 3% 8% 17% 21% With subsidies the NPV of average project of CHP becomes positive after 6-9 years of operation (Fig. 8, 12). With subsidies the IRR of CHP project is 12-16 per cent and 17-21 per cent after 12 years in case of pessimistic and sensitivity analysis accordingly (Table VII). With subsidies the CHP project is very profitable with high level of NPV and IRR values. Without based on results of this analysis, it can be stated that profitability of CHP projects will depend mainly on fuel costs and operation mode of the plant as well as the power plant possibility to follow electricity market price signals. V. CONCLUSIONS In the analysis, the focus was given on the comparison of investment decisions in wind parks and CHP plants under uncertainty of different variables. Access to financing and national support schemes play an important role in determining final power generation choices, but it is important to take into account different uncertain variables, like investment cost or revenues from the market, when making investment decision or setting justified subsidy schemes. As it is shown in the paper, these variables can differ depending on region, country or market area. Subsidy variations, if not designed with care, may be used by retailers to increase their own profits to the disadvantage of consumers in a sellers market. The cost-efficiency of tariffs for society decreases when policy makers overestimate the cost of producing renewable electricity. This is because the level of tariffs is based on future expectations of the generation cost of renewable electricity. When these turn out lower than expected, producers receive a windfall profit. It is therefore important that tariffs are reviewed regularly in order to adjust the system to the latest available generation cost projections and to stimulate technology learning. Furthermore, payments should be guaranteed for a limited time period that allows recovery of the investment, but avoids windfall profits over the lifetime of the plant. It can be concluded that the level of today's subsidies is too high for each type of considered power plant. However without subsidies most of projects can occur to be unprofitable. Consumers should know the estimates of the cost of environmental target and relevant energy project costs. If it be decided to valid a costlier policy, it needs to be articulated openly and honestly, giving stakeholders robust forecasts of the costs and benefits. 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