Optimal Generation and Transmission Planning for Renewable Energy in the Philippines, Study Guides, Projects, Research of Economics

Download Optimal Generation and Transmission Planning for Renewable Energy in the Philippines and more Study Guides, Projects, Research Economics in PDF only on Docsity! University of Hawai`i at Mānoa Department of Economics Working Paper Series Saunders Hall 542, 2424 Maile Way, Honolulu, HI 96822 Phone: (808) 956 -8496 www.economics.hawaii.edu Working Paper No. 16-13 The Public Economics of Electricity Policy with Philippine Applications By Majah-Leah Ravago James Roumasset September 2016 The Public Economics of Electricity Policy with Philippine Applications* Majah-Leah Ravago and James Roumasset† University of the Philippines, University of Hawaii and Energy Policy and Development Program Abstract Electricity policy in many economies is charged with multiple objectives including affordability, sustainability, inclusivity, and renewability. Unless these objectives can be reconciled, the pursuit of one will detract from the pursuit of another. We provide a framework for culling some objectives and reconciling other by extending the traditional view of efficiency. Philippine power policies are characterized and evaluated with respect to conflicting objectives and the problem of incomplete deregulation. We also make preliminary suggestions regarding investment planning for generation and transmission, including the suitability of short-cut metrics such as levelized and avoided costs and the prospects for increased competitiveness. JEL codes: Q4, Q48, Q41 Keywords: Electricity, renewable energy, excess burden, deregulation, competition, Philippines * This research reported here is a product of the Energy Policy and Development Program (EPDP), a four-year program funded in part by the U.S. Agency for International Development (USAID) and implemented by the UPecon Foundation, Inc. The contents or opinions expressed in this paper are the authors’ sole responsibility and do not necessarily reflect the views of USAID, the United States Government or the UPecon Foundation, Inc. Any errors of commission or omission are the authors’ and should not be attributed to any of the above. † Majah-Leah Ravago is Assistant Professor at the University of the Philippines and Program Director of the Energy Policy and Development Program (EPDP) of the Philippines. James Roumasset is Professor Emeritus (pending) at University of Hawaii and an EPDP fellow. This paper benefited from the comments of participants of the EPDP Research Workshop held in Tagaytay City on 6 Nov. 2015. We thank J. Kat Magadia and Shirra de Guia for their excellent research assistance, Arlan Brucal and Karl Jandoc for their help with the graphs, and Arsenio Balisacan, Lee Endress, Matthias Fripp, Michael Roberts, Steve Salant, and Nori Tarui for useful discussions. 3 The cost-effectiveness of pro-poor pricing (e.g., increasing block or “lifeline” rates) can be similarly evaluated. Since extending access by the means listed above and charging full-cost rates would not provide much benefit to the poor, one must compare the cost-effectiveness of subsidizing rates to low-income consumers with other programs such as contingent-cash transfers. On the other hand, removing existing distortions (e.g. artificial limits to competition and ratepayer-funded subsidies) that lead to unnecessarily high prices will help both non-poor consumers as well as poor households with access to electric power. 1.3 Renewability While renewability is commonly regarded as an objective, this is a category mistake.5 Renewability is a possible means to the end of environmental quality. Asserting it as an end in itself suppresses the requisite analysis. Externalities due to carbon and other emissions can be internalized by taxing emissions according to the damages that they inflict. This will promote renewable and clean energy as the eventual scarcity drives petro-chemical prices up and innovations reduce the costs of renewable sources such as solar (Chakravorty et al. 1997). As illustrated in what follows, using renewable subsidies to distort this efficient transition leads to unnecessary burdens and economic waste, exacerbated by the increased taxation needed for their finance. 1.3.1 Taxpayer-funded subsidies Figure 1 portrays the case of a taxpayer-funded subsidy to make an economy self-sufficient in energy by displacing power from imported petro-chemicals with domestically-produced renewable energy, such as wind and solar. Perhaps the most common vehicle for the deliverance of the subsidy is a tax-credit offsetting part of the cost of purchase. For many years in Hawaii, for example, consumers could get a 65% rebate on the cost of photovoltaic systems through Federal and State tax credits. Assume that burning petro-chemicals incurs a marginal damage cost equal to the value of the incremental damages from pollution and carbon emissions. The marginal social cost of power generation from such polluting non-renewable sources (MSCNR) is given by the marginal private cost of generation (MCNR) plus said marginal damage cost. Socially efficient production occurs where MSCNR intersects the demand curve, D, which in turn represents marginal social benefits. Self-sufficiency is attained via a subsidy (intersection of D and “MCR w/ subsidy”) just high enough to entirely displace non-renewables. As shown, the primary source of deadweight loss (excess burden, EB) is the extra costs of attaining a renewable portfolio standard of 100%, including costs of smoothing intermittent production to fit the load demanded by consumers. In a competitive environment or well-regulated monopoly scenario, renewable subsidies would also lower the price of electricity to consumers below the marginal social cost, including 5 Dasgupta (1995) similarly suggests that strong sustainability involves a category mistake. Under what conditions maintaining the stock of natural capital promotes intertemporal welfare is a matter for analysis, not assertion (see e.g. Endress et al. 2005). 4 pollution costs (Borenstein 2012b). This results in the small additional excess burden triangle as shown. Another source of excess burden is the fiscal costs of the subsidy. Since the subsidy itself is a transfer, that does not in itself cause economic loss. The excess burden comes from the taxes required to finance the subsidy. As surveyed by Bird (2005), estimates of marginal excess burden (MEB) vary widely. For the U.S., Ballard et al. (1985) estimate an MEB from 17-56%, Feldstein (1995) a much higher 165% and Diewert et al. (1998) conclude that MEB should be a minimum of 23%. In his estimate of the excess burden of Hawaii’s Clean Energy Initiative, Endress (2013) uses the conservative estimate of 25%, which is used in the illustration (Figure 1). Figure 1. The excess burden of a taxpayer-funded self-sufficiency subsidy The terminology of the double dividend debate may be instructive. The double dividend of emission taxation refers to the benefits of internalizing the marginal damage cost of emissions (first dividend) and the additional dividend from recycling the revenue obtained through a reduction in other distortionary taxes.6 In our example of a subsidy instead of a tax, both these dividends are negative. Moreover, the first dividend has two parts: the (large) excess cost of power provision and the (small) cost of marginal benefits being below marginal social costs. The 6 The term “double dividend” was coined by David Pearce (1991). 5 second negative dividend is the extra tax friction needed to finance the subsidy, e.g. 25% of the revenue rectangle. 1.3.2 Tied to be FIT Instead of a taxpayer-funded subsidy on supply, many countries rely instead on feed-in tariffs (FITs) for the promotion of renewable energy. We assume that the retailer/distributor is mandated to buy a certain percentage of their sales from renewable sources and that regulation succeeds in emulating competition.7 How should FIT rates be set? Figure 2 illustrates the case wherein the regulator sets a “self-sufficiency” price such that electricity demand (D) equals the domestic supply (MCR) of renewable-sourced power by equating the FIT to the difference between the self-sufficiency price and the marginal cost of the non-renewable substitute (MCNR). For the typical assumption that the demand curve is more inelastic than the supply curve, one can readily observe that the supply-side burden has been reduced more than the demand-side burden has increased. The high retail price reduces the quantity demanded, thus displacing the highest cost renewable energy. Since this type of FIT is fully funded by ratepayers, it does not require raising other taxes and incurring a negative revenue recycling effect. Thus it appears, on the basis of the “two dividends” that the FIT is considerably less than the taxpayer subsidy, i.e. taxpayer gains are more than consumer losses. Figure 2: The Excess Burden of a Uniform Feed-in Tariff 7 Inasmuch as costs are increased, rate-of-return regulation would further increase profits and warrant even higher prices. 8 the appropriate carbon tax in the Philippines would be the full $25.14 But even absent a global climate-change agreement, taxes on local pollutants (primarily SO2, NO2, and particulates) are still warranted and will stimulate the market to provide renewable substitutes. All things considered, emission taxes of 10-15% on coal could be justified even without a binding global agreement.15 Another appropriate target for policy intervention is the internalization of externalities from knowledge spillovers. In particular, subsidies for R&D aimed at lowering the cost of sourcing electricity from renewables are warranted (Acemoglu et al. 2012). But again, this is a global externality. If an agreement were in place, the Philippines should contribute its appropriate share of the R&D subsidy. Otherwise, the subsidy should be set according the Philippine share of benefits from the additional knowledge produced. If the Philippines is unlikely to have a comparative advantage in things like solar panels and wind turbines, this share would be quite small (and technical progress in renewable-sourced electricity will continue without Philippine subsidies). However, R&D subsidies may be warranted on adaptive research, for example, on renewable designs that are more suitable to the Philippine economy. The percentage of electricity from renewables will increase without RPS mandates or unwarranted subsidies as non-renewable resources are depleted, technical change continues, and externalities are appropriately internalized (Chakravorty et al. 1997 and 2008). In addition, government policy can facilitate the greater use of renewables in accordance with its role in pursuing economic efficiency. In particular, the following are in line with Adam Smith’s night-watchman functions and should be pursued as efficiency warrants. 1. Providing an informative transmission investment plan based on calculations of optimal generation mix and location, including flexibility of said plan regarding new generation opportunities identified by the private sector. 2. A well-functioning forward market allowing independent intermediaries to enter the retail market. 3. Streamlining red tape regarding the entry of new generating facilities. 4. Providing information to potential investors regarding a state-of-the-art menu of renewable techniques. 5. Technical assistance in the installation and operation of generating facilities. 6. Training technical personnel. 7. Assistance with technical and financial feasibility studies. 8. Overseeing the upgrading of transmission and distribution infrastructure, in particular to accommodate the intermittency associated with greater penetration of Variable Renewable Electricity (VRE), primarily solar and wind power. 1.4 Other objectives 14 If the Philippines were part of an incomplete global coalition, the optimal carbon tax for coalition members would be correspondingly less (Nordhaus 2015). A $25 carbon tax converts to $92/ton of CO2. 15 A ton of coal emits 2.86 tons of CO2. In the face of unemployment, a case can also be made for taxes on domestic coal production to be less than the taxes on imported coal. 9 While the over-riding objective of economic policy is social welfare, other possible intermediate objectives can be found in documents dealing with electricity policy, for example in the Philippines (see Section 2.2). Among these are reliability, affordability, and self-sufficiency. Like renewability, self-sufficiency as an objective can be rejected as a category mistake and, as discussed above, for reducing social welfare. Reliability as an intermediate objective would require extending the basic efficiency principles discussed above to account for uncertainty such as demand fluctuations, equipment failure, intermittency problems, and natural disasters. Affordability follows from the efficient pursuit of consumer welfare, modified by the equity considerations discussed under inclusivity in section 1.2. The pursuit of multiple objectives is likely to be infeasible, e.g. as in the case of economic growth, poverty alleviation, and environmental preservation when these are misleadingly viewed as separate components of sustainable development (Ravago et al. 2010).16 And even if the over-arching goal of intertemporal welfare is replaced by multiple well-defined (albeit arbitrary) metrics, we are still left with the problem of how the objectives are to be weighed. The proliferation of objectives thus removes accountability in setting priorities for public spending and sets the stage for unlimited rent-seeking since almost any program can be justified on the grounds of some subset of objectives. And when the government programs retard or fail to advance other objectives, the response is often to patch on ever increasing mandates, subsidies, and other distortions resulting in a black hole of government spending (Roumasset 2000). In cases where the government commitment to a particular objective is clear, the key is to interpret that objective as a dimension of the common good. As discussed above, this leaves several avenues by which the government can facilitate the integration of more renewable sources in ways that reduce the cost of power, including environmental costs. 2. Deregulation and market organization 2.1 Unbundling Complete electricity deregulation is often presumed to require unbundling all of the basic functions of electricity provision, i.e. into generation, transmission, retailing, and distribution, and the formation of forward and spot wholesale markets under the auspices of a market governing authority. Generation and retailing are suitable for privatization and competition. Transmission and distribution are commonly regarded as natural monopolies due to the potential for inefficient duplication of network infrastructure. It appears that there are economies of scope in transmission. Instead of, say, building transmission lines from each generator to specific 16 Another example is the National Food Authority’s pursuit of low and stable prices for consumers and high and stable prices for producers (Roumasset 2000). 10 distribution substations, one can imagine that the network is pooled by means of a trunk line “hub” that is joined to the substations by “spokes”.17 In the New Zealand variant of unbundling, companies are allowed to have both generation and retailing arms. Generating and retailing divisions, however, are not allowed to have bilateral contracts with one another. Instead, generators must sell all of their power to the wholesale market and retailers must buy all of their electricity from the market. Moreover, the bids from the generating and wholesale arms must be within 5% of one another. This incentivizes each division to act as if they are competitors in a completely unbundled market while retaining possible economies of scope in generation and retailing. The country has accordingly achieved a highly efficient wholesale market and efficient operation of generation and retailing, even without complete unbundling.18 The USA has largely deregulated generation but has left several large “utilities” in place that handle both retailing and distribution. This requires regulation of retail pricing. Instead of simply setting prices that limit the rate of return on capital, today’s regulators attempt to control expenditures as well, aiming to set regulations to motivate utilities to undertake efficient investments. However, this ideal is sometimes compromised by the “other objectives” problem, e.g. the pursuit of renewable energy and repaying stockholders who have been victims of previous attempts at deregulation (Borenstein 2012a, 2012b). 2.2 The Philippine case Before the landmark passage of the Electric Power Industry Reform Act (EPIRA) in 2001, the power industry in the Philippines was vertically integrated and the National Power Corporation (NPC) had monopoly over power generation and transmission.19 Appendix A provides the history of power policies in the Philippines and the structure of the industry before and after EPIRA. Despite private sector investment in 1993-1994, reliability problems continued, end-consumer rates were still highest in the region, and the distribution network was characterized as being highly fragmented (DOE 2000; Villasenor 2000). The operation of NPC, a government owned and controlled corporation, had accumulated a huge debt, exacerbating the country’s already stressed fiscal situation.20 17 Noble Laureate Vernon Smith (1993, 1996) argues in contrast that the common observation of parallel transmission lines suggests that competition among transmission providers may also be feasible. 18 If there are further efficiency gains to be made, it appears that these may come from the transmission and distribution sectors, which account for 50% of electricity rates (personal correspondence with the CEO of New Zealand’s Electricity Authority). 19 Before EPIRA, Executive Order (EO) 215 put an end to monopoly power in generation by the NPC in 1987. 20Another contributing factor was the failure to complete and operationalize the Bataan nuclear power plant, partially constructed under dubious contracting arrangements during the Marcos administration. The Build-Operate-Transfer (BOT) Law (RA 6957) was partially motivated by a desire to improve incentives in electricity generation, but it proved to be too late. 13 Figure 4. Market Concentration in Generation, Visayas 2.2.2 Lack of competition in the retail sector Under EPIRA, the retail sector is envisioned to eventually become competitive. Provisions of the Retail Competition and Open Access (RCOA) are aimed at gradually growing the “contestable” retail market so that all consumers including households would be eventually able to switch retailers anytime, e.g. as in Singapore and New Zealand. Four years after its intended implementation, RCOA’s commercial operation and its integration with the wholesale spot market commenced in June 2013. ERC suspended licensing of suppliers in October 2014, however, due to unresolved issues regarding license issuance to retail suppliers. Further delays in implementation caused generators to contract with DUs instead of reserving power for open access.24 The suspension was lifted in April 2016 when ERC issued a resolution adopting new rules regarding licensing and other requirements. The mandatory inclusion of consumers with 750KW of monthly consumption was also postponed until June 2017. As a result of these delays, the analysis of the distribution function cannot be entirely separated from the retail function. Appendix B describes the companies and extent of 24 Lotilla (2015) in his presentation at the UPSE-Ayala Lecture Series. 14 competition in the distribution sector. Even if RCOA were realized, retailing would not be completely unbundled from generation due to the provision of limited cross-ownership, whereby a distribution utility is allowed to source no more than 50%25 from its affiliate generation company. This provision poses a concern to EPIRA’s goal of making the retail sector competitive inasmuch as cross-ownership allows for transfer pricing.26 In competition law, the concept of relevant market matters. It is defined as the intersection of the relevant product market and the relevant geographic market. For distributors, the relevant markets have been exogenously defined as franchise areas. As of December 2015, contestable customers make up 20% of consumption in the Meralco franchise area (Figure 5). Meralco serves to 55% (11/20) of these through its retail subsidiary, MRLCOLRE. Other electricity retail suppliers (RES) serve the remaining 45%. Figure 5. Retail concentration in the Meralco Franchise area Source: PEMC Annual Retail Market Assessment Report (2015) There are only about 376 registered contestable customers in the entire Philippines -- mostly industrial and commercial users given the requirement of 1MW average consumption per month. MRLCOLRE serves 212 of these (56%). The next largest retailer, AESIRES (a subsidiary of Aboitiz Energy Solutions, Inc.) serves 51 contestable customers or 14% of the consumption market (see Figure 6). 25 Sec 45b of EPIRA states that: “no distribution utility shall be allowed to source from bilateral power supply contracts more than fifty percent (50%) of its total demand from an associated firm engaged in generation...” 26 By increasing fees paid to their generation subsidiaries, distribution utilities are able to lower their total tax burden. Meralco CCs 11% Other retailers9% Captive80% 15 Figure 6. Retail concentration in the Philippines Source: PEMC Annual Retail Market Assessment Report (2015) Note: MRLCOLRE is Meralco’s subsidiary, AESIRES is the retail arm of Aboitiz Energy Solutions, Inc., ADVENTRES is AdventEnergy, Inc., DIRPOWRES is DirectPower Services, Inc, EPMIRE is Ecozone Power Management, Inc., ADVENTRES is AdventEnergy, Inc. 3. Optimal investment and Pricing: The Philippine Case 3.1. Methods for determining optimal generation and transmission How should investment priorities for generation and transmission be evaluated? It is common to rank investments in generation according to the levelized cost of electricity (LCOE), a technique that spreads construction, operation, and maintenance costs over the expected stream of power output to obtain the costs per kilowatt hour of various technologies. Sometimes, LCOE is used in combination with estimates of how much of each technology could be implemented under specified scenarios (for example, hydro-electric and geothermal power may be limited by geography). Now by “stacking” these quantities from low to high unit cost, you get what looks very much like a supply curve. It is easy to see the appeal of this technique among economists. ADVENTRES5% AESIRES14% DIRPOWRES9% EPMIRES7% MRLCOLRE56% OTHERS9% 18 sharply after that. Assume further that gas can be turned down to 25% without substantial loss in efficiency. To make things concrete, set peak demand at 10,000MW, off-peak demand at 5,000MW and assume that both periods are 12 hours. One feasible solution would be to build coal plants to satisfy 5,000MW of capacity and to run them at 75% during off-peak hours. This leaves 5,000MW of required gas capacity during peak hours. When run at 25% of capacity, gas production merely fulfills the remaining off-peak requirement. Abstracting from transmission costs, we can now compare the levelized costs for both cases, since we know how many hours the capacity costs must be spread over. If the LCOEs of coal and gas are unequal, we expand the lower cost option and reduce the other until the two levelized costs are equal. If gas plants can simply be turned off with little efficiency loss, we may find a corner solution in which coal is said to be a “baseload fuel” and gas facilities are reserved as peaking plants. This is not an inevitable solution, however, inasmuch as lowering the hours of operation for the gas plants increases their LCOE. This may also help to explain why the falling relative cost of natural gas in the U.S. (along with pending environmental regulations) led to a dramatic decline of coal-fired generation. There is a penalty associated with the flexible use of coal for both peak and off-peak hours justified only by the lower fuel costs. Figure 8 is an amplified portrayal of the Luzon grid and major generating facilities on the island of Luzon. Observing the far north of the island, one can see that in low-demand areas where coal is too costly at correspondingly low capacities, it is cheaper to send coal generated electricity north from the more Southern plants. This means, however, that shadow prices in the far north include higher transmission costs and will accordingly be higher than at locations nearer major generating facilities. And in peak periods, the shadow prices in, say, Laoag City in the far northern province of Ilocos Norte will be given by the marginal cost of gas power plus the relatively high transmission costs from Batangas to Laoag. This means that the avoided cost of developing wind and solar in the far north is relatively high such that the LACE values may be above levelized cost even without subsidies, at least at low levels. Imagine an off-take substation in the far north for example with a peak load of 200MW, an off-peak load of 50MW, and shadow prices of 20 and 5 pesos per KWh, respectively. Consider a wind plant that generates 25MW during the day (peak) and 50MW at night (off peak). Avoided cost is 25MWh times 20,000 pesos/MWh plus 50MWh times 5,000 pesos/MWh all times 12 hours per period. This equals 12(750,000) pesos or 375,000 pesos per hour of avoided cost for the project.29 As long project costs are less than this, the project is warranted. Larger plants will have a lower avoided cost at the margin since there would be surplus power at night. Moreover, the levelized cost at the margin will increase since the project cost must be spread over a smaller total number of units (actual generation would be adjusted below full potential at night). Wind power should be expanded until the marginal avoided cost (benefits) equals the marginal levelized cost (Ueckerdt 2013).30 29Roughly equivalent to $8,000 of benefits per hour for the project. 30There is no need to account for environmental benefits of renewable energy so long as local pollution externalities have already been internalized by emission taxes. 19 Figure 8: Luzon grid and sources of generation As we can see from this example, in the long-run optimization, LACE values are the same as the optimal shadow prices. If gas-fired generation were used to meet marginal peak demands, peak shadow prices in the North would be given by the levelized cost of gas-fired power in Batangas (near Manila) plus transmission costs. Off-peak shadow prices are given by the levelized cost of coal-fired power at the nearest in-take substation plus transmission costs. Some iteration may be required in obtaining the solution since we don’t know the exact output before knowing the required loads. And we don’t know the optimal loads without specifying demands at the off-take substations. It is in this sense that supply is not independent of demand, even in the case of constant costs of expanding capacity. Since solar is a better fit with peak-use periods, it will have higher LACE values than wind power although the levelized costs of solar are typically higher than that of wind as well. In practice, both wind and solar are used in the north (Figure 8). The same logic should apply to the far South, since gas-fired power is also being transmitted long distances to combine with the coal plants located in Iloilo and Cebu (Figure 9). 20 This time solar dominates wind, however, due to the fact that there is greater total solar energy at the lower latitude and because the wind profile is somewhat less attractive.31 Figure 9: Bicol and Visayas Regions The above provides a sense in which optimal generation capacity can be determined under simplifying assumptions about transmission costs and given loads. If demand curves instead of loads are specified, an iterative procedure can be used whereby the initial loads are approximated, e.g. by actual loads. Next, the optimal shadow price is plugged into the demand schedules, the new load is used as the starting point, and so on. Alternatively, the optimal solution can be determined by the optimal satisfaction of the corresponding first order conditions. Shadow prices at the input substations are given by the levelized cost of the marginal source, evaluated at the quantity supplied. Shadow prices at the off-take substations are given by the shadow price at the marginal source times the percentage of power remaining after deducting the percentage loss as a function of distance and resistance. For example, the shadow price at a major off-take station in the North during peak periods is given by the shadow price of power at the intake substation for gas-fired power (in Batangas) times said percent remaining after transmission. 31 The ideal is sustained winds at 20-40 mph. Winds that reach 45mph or higher are damaging to the turbines, such that the windmills have to be shut down. In addition, the turbines may be damaged during typhoons (which are more frequent in the Visayas). 23 (Kahn 1970, Joskow and Wolfram 2012). This results in individualized prices assigned to peak and off-peak periods, which are then added to marginal variable costs to determine the efficiency prices for each period.36 Marginal cost pricing may lead to either a revenue surplus or deficit depending on whether marginal cost is above or below average cost (Munasinghe 1981). Either is possible. If electricity is being expanded at the intensive margin some economies of scale may be realized. But if power provision increases at the extensive margin, increasing marginal cost is more likely. Even at the intensive margin, the common observation of widely dispersed generation and parallel transmission lines suggests that economies of scale in generation and transmission have already been exhausted (Smith 1993, 1996). In the case of increasing marginal costs, marginal cost pricing is compatible with block pricing, where inframarginal blocks are charged rates lower than marginal costs, a solution that also promotes equity. The classic result of pricing according to long run marginal costs derives from the assumption of the certainty and the resultant coincidence of short and long run marginal costs. Once uncertainty is admitted, efficiency pricing should be according to short run marginal cost. But it is not necessarily the case, as commonly assumed, that short run marginal cost is below long run. Once short run marginal cost is properly adjusted for running higher cost generation facilities and line losses/constraints in transmission, short run marginal cost in periods of high demand will be above the expected long run optimum. The classic literature just reviewed did not distinguish between wholesale and retail prices. Under the assumption that generation originates at a single point and transmission and distribution are priced at marginal costs, this omission is not important. There is just one wholesale shadow price and optimal retail prices are given by the wholesale price plus the marginal cost of transmission and distribution to each location. In the case of multiple generation locations, optimal wholesale prices are in effect FOB or CIF prices depending on whether the substation is a net importer or exporter of power (Jandoc et al. 2015). It is imaginable, as argued by Smith (1993, 1996), that generation, transmission, retailing, and distribution could all be privatized and that a well-organized market could deliver the optimal shadow prices just described. However, no system worldwide has gone that far. Even where there are well-developed wholesale markets, transmission and retailing remain regulated. Even in the partially deregulated US market, for example, retail prices are largely divorced from optimal pricing levels due to the competing and often conflicting goals of regulators (Joskow and Wolfram 2012). As discussed in Section 2.2, the disconnect between optimal and actual retail prices is likely to be even larger because the wholesale spot market is very thin, there is no forward market, and retail markets are not competitive. With a well-developed forward 36The usual textbook treatment of peak load pricing is a special case of this result, wherein the off-peak demand for additional capacity at marginal cost is zero. In the case of the internal solution, the terms “peak” and “off-peak” may be misleading in the sense that both periods use the full capacity. The difference is simply that one demand curve lies above the other. 24 market and deregulated retailing, competition is likely to bring a closer convergence of wholesale and retail pricing. This has the potential to increase consumption and welfare overall while at the same time conserving on usage during times of greater scarcity. 3.3 Subsidies for renewables: An illustration of FIT Instead of the uniform-subsidy case of FIT illustrated in Figure 2, the regulatory authority typically establishes different rates for different generation sources. In the extreme case shown in Figure 10, the authority acts as a discriminating monopolist, such that competitive suppliers are each paid according to their marginal costs.37 Figure 10: The Excess Burden of a Perfectly Discriminating FIT Notes: JMD: Additional Production Cost = $ 1,712,328/hour KMP: Lost Consumer Benefits = $ 570,776/hour Total Economic Waste = $2,283,104/hour = $ 20 billion/year Demand as function of price: Q = 14400 – 24P Supply as function of price: Q = -96 + 1.76P Source: Roumasset et al. 2016 This lowers the ratepayer total amount of the ratepayer subsidy and the price increase needed to finance that subsidy, thus decreasing the amount of demand-side waste. The problem is that 37 As discussed above, however, this is easier said than done because levelized costs are not a sufficient foundation for determining a least-cost FIT schedule. 25 lower prices means that higher marginal costs of renewably-generated power must be incurred because of the greater equilibrium consumption. This results in the supply-side excess burden increasing more than the demand-side burden declines. Despite this disadvantage, it is still possible that the discriminatory approach may be preferred on account of the smaller tax interaction effect that lower retail prices imply (to say nothing of the political infeasibility “non-discriminatory” price increase). Roumasset et al. (2016) estimate that the total deadweight loss of this policy could be as high as one trillion pesos per year, as illustrated in Figure 10. Accounting for the fact that actual FIT subsidies are inevitably far from those implied by the least-cost marginal cost schedule would make the estimate even higher. 4. Concluding remarks A first step in understanding investment needs for new generation and transmission facilities will be to build a relatively simple analytical model to verify and apply the principles discussed above. One could begin, for example, with the major generation facilities and franchise regions in the Luzon-Visayas grid, with their costs of delivering power during different times of day, along with a simple specification of transmission costs and constraints. Once optimal use of existing facilities to meet current loads is determined, one can expand the model to allow for forecasted future loads, e.g. a 50% increase. If pricing policies are to be considered, one needs to replace exogenous loads with demand functions that gauge how responsive consumption would be to specific pricing reforms and other demand management schemes. Simple model specifications can utilize exogenously specified reserve requirements. If reserve policies are also to be analyzed, uncertainty about demand and equipment failure can be added to the basic model. The recommendations from the economic model would still need to be validated by a more complete engineering model with the full transmission network. One illustrative hypothesis that could be explored in the economic model is the possibility that existing spatial allocation of generation could be improved, e.g. by reserving gas power for its comparative advantage in serving peak demands, including in the Visayas. On the other hand, if transmission costs justify using gas power in Luzon only, it is possible that the ex post benefits of the Luzon-Visayas connection do not warrant the costs. This may provide cautionary insights regarding the benefits of connecting the Mindanao grid with the Luzon-Visayas grid. 4.1 Policy issues for further research Should the Philippines pass a renewable portfolio standards (RPS) law? Carbon taxation is not only more efficient (Acemoglu et al. 2012) but it is better for the poor because it grows the economy and lowers the price of electricity, which is consumed disproportionately by lower income households (with the exception of the 10% without access). RPS laws require extracting either additional taxes or higher rates for electricity, either of which potentially causes extensive excess burden. 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Project Operator Type Capacity in Megawatts Cost (P/kwh) as of bid date Cooperation period (years) Commercial operation date Contract expiration 1 Casecnan hydro electric plant National Irrigation Administration PPA 140 $0.165 20 Jan 2000 Jan 2020 2 Natural gas project KEPCO BOT 1200 1.2560 20 Jan 2002 Jan 2022 3 Sual Pangasinan Coal fired powerplant Hopewell Holdings Ltd. BOT 1000 25 Mar 1999 (phase I) June 2024 June 1999 (phase II) (1-10) 1.4370 (11-20) 1.3230 (21-25) 1.2070 4 Mindanao II (Mt. Apo) Geo. PNOC-EDC PPA 48.25 1.5500 25 Jul 1999 Jul 2024 5 Bakun A/B and C HEP NMHC/Ever/AEV/Pacif ic hydro BOT 65 2.650 25 Jan 2000 Jan 2025 6 San Pascual Cogeneration plant San Pascual Cogen Co. International BOO 304 25 June 2001 June 2026 (1-6) 1.6420 (7) 1.6210 (8) 1.4530 (9) 1.3280 (10) 1.2670 (11) 1.2230 (12) 1.2020 (13-25) 0.9510 7 Pagbilao coal fired TPP Hopewell Energy Ltd. BOT 700 1.7840 30 Ap 1996 (phase I) June 2026 June 1996 (phase II) 8 Caliraya-Botican-Kalayaan HEP IMPSA BROT 640 25 Jan 2004 Jan 2029 (1-3) 0.7000 (4-9) 1.6000 (10-25) 1.0400 Without pumping (1-3) 0.7000 (4-9) 1.0400 (10-25) 0.4300 9 Mindanao coal-fired powerplant I State/Harbin BOT 200 25 Jan 2004 Jan 2029 (1-5) (6-10) 1.4530 (11-15) 1.4940 (16-20) 1.5410 (21-25) 1.5910 10 San Roque multi-purpose HEP Marubeni/SITHE/Italia n-Thai BOT 345 3.3550 25 Jan 2005 Jan 2030 11 Ambuklao Hydro Power Plant Miescor ROL 75 1.3500 5 Oct 1995 Oct 2000 12 Bauang, La Union Diesel PP First Private Power Corp BOT 215 1.3730 15 Feb 1995 Feb 2010 13 Bataan EPZA Diesel Plant Edison Global Electric BOO 58 1.6340 10 Jun 1994 Jun 2004 14 Benguet (Amphohaw) Mini hydro Hydro Elect. Dev. Corp ROL 22 88% *NPC rate 5 June 1992 June 2002 15 Binga Hydro Power Plant Chiang Jiang Energy Corp. ROL 100 1.1500 15 Aug 1993 Aug 2008 34 Appendix Table 1 continued: List of Independent Power Producer projects. With the passage of EPIRA, the landscape shifted primarily to private ownership, with growing competition in the generation sector and the intention to make retailing competitive as well. Figure A2 shows the structure with four sectors: generation, transmission, distribution, and retailing (called “supply” in the Law). As discussed in the text, retail competition was to be achieved by the gradual expansion of the “contestable market,” the “segment of electricity end-users who have a choice” among retailers. The industry restructuring will not be complete without the full implementation of the Retail Competition and Open Access Law. Even with said implementation, however, the industry will not be fully competitive without a forward market Project Operator Type Capacity in Megawatts Cost (P/kwh) as of bid date Cooperation period (years) Commercial operation date Contract expiration 16 Calaca Batangas Diesel Plant Far East Levingston (FELS) BOO 90 1.7790 5 Sept 1993 Sept 1998 17 Cavite EPZA Diesel Plant Magellan Cogen Utilities BOO 43 1.3460 10 Dec 1995 Dec 2005 18 Clark Air Base Diesel Plant Electrobus Consolidated Inc. ROM 50 1.1400 7 Jul 1992 Jul 1999 19 Engineering Island Power Barge Sabah Shipyard SDN, BHD BOO 100 1.5680 5 Oct 1994 Oct 1999 20 Gas Turbine (GT) Power Barges Hopewell Tileman Ltd. ROM 270 1.9630 10 1993 2003 21 General Santos Diesel Plant Alsons/Tomen BOO 50 1.5260 18 Ap 1998 Ap 2016 22 Iligan City Diesel Plant I Alsons/Tomen BOT 58 1.4370 10 Jul 1993 Jul 2003 23 Iligan City Diesel Plant II Alsons/Tomen BOT 40 12 Dec 1993 Dec 2005 (1-7) 1.5250 (8-12) 1.3180 24 Leyte A (Leyte-Cebu) Geo PNOC-EDC PPA 200 1.6500 25 Nov 1997 Nov 2022 25 Leyte A (Leyte-Cebu) Geo PNOC-EDC PPA 440 1.5500 25 Jul 1998 Jul 2023 26 Limay Bataan CC, Block A ABB/Marubeni/Kawas aki BTO 300 0.9200 15 SC May 1994 Oct 2009 CC Oct 1994 27 Limay Bataan CC, Block A ABB/Marubeni/Kawas aki BTO 300 0.9340 15 SC Apr 1993 Jan 2010 CC Jan 1995 28 Makban Binary Geo Plant ORMAT Inc. BTO 15.73 0.3370 10 Mar 1994 Mar 2004 29 Malaya Thermal Power Plant KEPCO ROM 650 15 Jun 1995 Jun 2010 Unit I (1-4) 0.1670 (5-15) 0.3070 Unit II (1-4) 0.1530 (5-15) 0.2790 30 Mindanao Diesel Power Barge Mitsui/BWSC BTO 200 15 Apr 1994 Jul 1994 Apr 2009 (1-7) 0.7840 (8-15) 0.7950 31 Mindanao I (Mt. Apo) Geo PNOC-EDC PPA 47 1.5578 25 Feb 1997 Feb 2002 32 NAGA Thermal Complex SALCON ROM 203 15 May 1994 May 2009 CTPP-1 1.2790 CTPP-2 1.7980 CDDP-1 1.3790 GT 1.8600 33 Navotas Diesel Power Barge I East Asia Power Corp. BOO 60 1.5598 5 Sept 1994 Sept 1999 34 Navotas Gas Turbine No. 4 Hopewell Energy Int'l Ltd. BOT 100 2.0690 12 Mar 1993 Mar 2005 35 Navotas Gas Turbines Nos. 1-3 Hopewell Holdings Ltd. BOT 210 2.0640 10 Jan 1993 Jan 2003 36 North Harbor Diesel Barges Far East Levingston (FELS) BOO 90 1.5670 5 Jul 1994 Jul 1999 37 Pinamucan, Batangas Diesel PP Enron Power Corp. BOT 105 2.0190 10 Jan 1993 Jan 2003 38 Subic Zambales Diesel Plant I Enron Power Corp. ROM 28 1.5487 5 Jan 1993 Jan 1998 39 Subic Zambales Diesel Plant II Enron Power Corp. BOT 108 1.6590 15 Mar 1994 Mar 2009 40 Toledo Cebu Coal Thermal Plant Atlas Consolidated Mining PPA 55 1.00 10 Jul 1993 Jul 2003 41 Zamboanga Diesel Power Plant Alsons/Tomen BOO 100 1.4730 18 Dec 1997 Dec 2015 Note s: PPA Power purchase agreementBROT Build, rehabilitate, operate, transfer BOO Build-own-operate BOT Build-own-transfer Source: Reside (2001) and National Power Corporation as cited in the World Bank Country Framework Report for Private Participation in Infrastructure (2001), Aldaba 2004 35 such that independent retailers will not be at a disadvantage in being able to secure reliable service to their customers. Figure A2. The Electricity Industry Structure after EPIRA (2001-present) With the change in landscape, the actors and their roles have also changed. The DOE still has policy and planning responsibilities and oversees NPC and NEA. NPC divested its ownership of government assets through the creation of Power Sector Assets and Liabilities Management (PSALM), which is in charge of asset privatization. The function of NPC has been reduced to missionary electrification including some ownership of Small Power Utilities Groups (SPUGs). NEA still supervises the electric cooperatives. EPIRA also created the National Transportation Company (Transco) that owns the transmission assets. The grid is managed by a concessionaire, the National Grid Transmission Corporation (NGCP, Figure A2), which is responsible for the improvement, expansion, operation, and maintenance of the transmission assets. The DOE established the Wholesale Electricity Spot Market (WESM), which provides a market and thus, pricing for the uncontracted power outside of the bilateral contracts. WESM is run by the Philippine Electricity Market Corporation (PEMC), which took over as the independent market operator in 2003. EPIRA created two oversight entities -- the Energy Regulatory Commission (ERC), which replaced ERB (see Figure A1 and A2) and the Joint Congressional Power Commission (JCPC). ERC 38 supportive of the goals of EPIRA, especially regarding market completion to bring down the cost of power. In furtherance of the RE law, the DOE released Circular 2015-07-0014 prescribing the policy of maintaining at least 30% of total generation coming from renewable sources as part of a fuel mix target of 30-30-30-10, i.e., 30% - coal, 30% - renewables, 30% - natural gas, and 10% - others. The incentive for the development of renewable energy resources in the country’s total power-generating capacity is facilitated through the implementation of the Feed-in Tariff System. This would not require increasing the renewable share but rather limiting the decrease. The renewable share was about 38% in the 1990s and average around 33% in 2011- 2014, largely from hydropower and geothermal. On the one hand, EPIRA aims to encourage competition and transparency in the power Industry. On the other hand, the Renewable Energy Act aims to reduce import dependence and price fluctuations with protectionist subsidies that shrinks the economy without any evidence that this will stabilize prices. Reforms that aim for “balance” among allegedly competing objectives of growth, health, and environment are not well-founded. A more cost-effective way to reduce emissions relative to direct regulation would be to tax the sources of negative externalities. 39 Appendix B: Market concentration among distribution utilities Distribution utilities are obligated to serve potential customers in their franchise areas c leaving them as monopolies absent viable retail alternatives. Under EPIRA, a new entrant to the distribution business requires a congressional franchise. A new entrant to the retail sector requires a license from the ERC. Appendix Table 2 reports the Herfindahl-Hirschman Index (HHI) of market concentration in distribution for the three main regions of the Philippines. The HHI is computed by squaring the market share of each firm in the market and then summing them up over firms. HHI ranges from close to 0 to 10,000. The closer the market is to a monopoly, the higher the concentration and the higher the HHI. As shown in Table 1, the highest HHI occurs in Luzon (6193), signifying a substantial degree of market dominance by Meralco. Appendix Table 2. Herfindahl-Hirschman Index (HHI), distribution utilities, 2014 kwh sold HHI Philippines 3520.60 Luzon 6193.87 Visayas 1519.46 Mindanao 1027.66 Note: HHI is computed based on the kwh sold to residential, commercial, industrial, and other customers. Source of basic data: The Rural Electrification Chronicle 2012-2014, National Electrification Administration (NEA), 2015; 2014 Private Investor-Owned Utilities Monthly Operations Report, Department of Energy (DOE), 2015. Figure A4 shows the largest distributors as of 2014. Meralco is the largest franchise holder, controlling 60% of the Philippine market. Their franchise area includes Manila and surrounding provinces. It’s market share of Luzon is 79% (Figure A5). This gives Meralco substantial monopoly power and monopsony power as it is by far the largest buyer of electricity from the generation companies. The next largest distribution utilities are Visayan Electric Company (VECO) with 4% and Davao Light Power Company (DLPC) with 3% (Figure A4). Aboitiz Power owns both VECO and DLPC. The remaining franchise areas are served by 122 electric cooperatives (ECs) and 14 Private Investor Owned Utilities (PIOUs). 40 Figure A4. Retail/Distribution concentration, Philippines Note: Shares are computed based on the kwh sold to residential, commercial, industrial, and other customers. Source of basic data: The Rural Electrification Chronicle 2012-2014, National Electrification Administration (NEA), 2015; 2014 Private Investor-Owned Utilities Monthly Operations Report, Department of Energy (DOE), 2015. Figure A5. Concentration in distribution, by broad regions Note: Shares are computed based on the kwh sold to residential, commercial, industrial, and other customers. Source of basic data: The Rural Electrification Chronicle 2012-2014, National Electrification Administration (NEA), 2015; 2014 Private Investor-Owned Utilities Monthly Operations Report, Department of Energy (DOE), 2015. Luzon Visayas Mindanao