Policy Framework for the Electric Power Industry in the Philippines’ NIC-hood: Quo Vadis?

Introduction

The objective of this Paper is to start a national conversation on the electric power industry in the Philippines with 2018-2029 timeline in mind. 

 The viewpoint taken here is that of the industry.  “Industry,” refers to the set of firms that satisfy the needs, wants, and expectations of the market and system, nationwide. “Market” peculiarly refers to power industry participants and consumers of electricity. “System” is the enfranchised concession of transmission and sub-transmission assets managed and operated by private sector.  Their ownership to date is with government. (EPIRA, 2001).

 The nature of the general problem confronting the industry can be broadly considered as both economic and financial.  Without prejudice to claims by other disciplines to the contrary, it is, generally speaking, an allocation problem (Samuelson) saddled with the intricacies considering the huge amounts involved.

 Thus, the threshold issue in energy economics in the Philippines is three-fold: “What to produce? How much to produce? For whom to produce?” (Lipsey & Steiner, Economics). Perforce, policy defined as “guideline for thinking,” must address these major aspects, three-fold, sine qua non.

 To paraphrase, the problem can be in terms of: What kinds of power plants (by fuel type) is the country looking at from 2018-2029?  How much electricity production are those plants capable of producing?  For whom consumer type, residential or industrial, and considering environmentalists’ advocacies versus price concerns, do the power generation players produce in 2018-2029?

In recent decades, power generation in the Philippines is an endeavour which mainly the private sector undertakes.  This is in keeping with the thoughts of Adam Smith who held that, “it is only the royal mail (or post office) that deserves government’s attention by way of subsidy.” 

Almost always in the recent past, it is the private sector that bears the risks from the time that building a plant is conceptualized, percolating the deal in its Preliminary-Front-End Engineering & Design (Pre-FEED) stage, putting up the early equity, packaging the financing, conferring with suppliers, securing licenses and permits, engineering, procurement, and actual construction (EPC), starting operations, and staying in business.

Consistent with the principle of the risk-return trade off, the higher the risk, therefore, higher returns are required.

Quite the harsh reality that it is, there persists the impression that something similar to the “tragedy of the commons” can be felt emanating from the power generation industry. Quite simply, this means that rational individual behaviour does not necessarily serve the welfare of society as a whole. (Hardin, Garrett, Tragedy of the Commons).

The Prospect of Emerging Opportunities

     Inexorably, opportunities are emerging within the timeline 2018-2029. This is the reason why the proposed national conversation on power generation is relevant and timely.

     Extrapolating from the observed 5.6% average GDP growth for the immediate past decade as mentioned in the Department of Energy website (www.doe.gov.ph), it stands to reason that power generation and GDP must grow in tandem.  Between 2018-2029, it is imperative that new power plants be constructed for two reasons: one is to replace the old plants; another reason is to supply more electricity to make further growth possible.

     It must be emphasized that power plants do not grow overnight. They have to be built brick by brick, from scratch usually, over five or more years, before they can produce electricity.  The availability of the grid, its N-1 contingency, is another vital aspect to consider.  In fact, the country’s Transmission Development Plan (TDP) is envisioned to anticipate growth from 2016 through 2040.

     In between, every time that the demand for electricity exceeds the available capacity, the dependable capacity, or the installed capacity, the risk of a power shortage emerges.

     The Table below presents the computations of the demand for electricity, year by year, for the period from 2018-2029. The starting point of the computations is based on the actual 2017 figures appearing on the 2017 Power Demand and Supply Highlights in the DOE website.

Table I: Projected Peak Demand, 5.6% Annual Increase, and Cumulative 5.6% Increase, 2018-2029, (In Megawatts of Electricity)
Column A	Column B	Column C	Column D
Year	Peak Demand	6% Annual Increase	Cumulative 6% Increase
2017	13,789	835 (actual)
2018	14,561	772	772
2019	15,377	815	1,588
2020	16,238	861	2,449
2021	17,147	909	3,358
2022	18,107	960	4,318
2023	19,121	1,014	5,332
2024	20,192	1,071	6,403
2025	21,323	1,131	7,534
2026	22,517	1,194	8,728
2027	23,778	1,261	9,989
2028	25,109	1,332	11,320
2029	26,515	1,406	12,726
Source of baseline 2017 data: Department of Energy website

      The above Table projects that demand is expected to increase by 82.10% from 14,561 MW in 2018 to 26,515 MW in 2029, under the assumption of a 5.6 % annual growth, which is a bit lower than the expected growth in GDP.  The cumulative growth in demand (12,726 MW) calls for investment in new plants and maintaining the operating efficiency of the existing power plants. Thus, the opportunity is there to recreate and/or reconfigure the power generation industry.

     The Table below presents the computations of the available capacity, dependable capacity, and installed capacity for electricity, year by year, for the period from 2018-2029. The starting point of the computations are from actual 2017 figures from the DOE website.

Table II: Projections for Available Capacity, Dependable Capacity, and Installed Capacity at 5.6% Growth, 2018-2029, (In Megawatts of Electricity)
Year	Available Capacity	Dependable Capacity	Installed Capacity
2017	14,458	20,515	22,730
2018	15,268	21,664	24,003
2019	16,123	22,877	25,347
2020	17,026	24,158	26,766
2021	17,979	25,511	28,265
2022	18,986	26,940	29,848
2023	20,049	28,448	31,520
2024	21,172	30,041	33,285
2025	22,357	31,724	35,149
2026	23,609	33,500	37,117
2027	24,931	35,376	39,196
2028	26,328	37,357	41,391
2029	27,802	39,449	43,709
Source of baseline 2017 data: Department of Energy website

  The above Table indicates that new installed capacity must rise to 43,709 MW by 2029 from 24,003 MW in 2018.

     That represents a target additional investment of at least 19,706 MW newly-installed capacity, assuming that all power plants operating in 2018 are still running in 2029.

     In a nutshell, what that means is 82.10% of present installed capacity must be generated in the next eleven years by new plants yet to be constructed. While at the same time, the old power plants must keep on running as efficiently as they do at present. 

The Prospective Threat

Table III: Concentration Matrix of Power Generation Capacity, By Location (In Levels and Per Cent)
GRID	POWER GENERATION CAPACITY (MW)		PER CENT SHARE (%)
	Installed	Dependable	Installed	Dependable
Luzon	15,128	13,874	70.0	71.0
Visayas	3,352	2,945	15.5	15.1
Mindanao	3,141	2,716	14.5	13.9
Total	21,621	19,536	100.0	100.0
Source: Department of Energy website

 

Table III above indicates that the installed power generation capacity is located 70% in Luzon and 30% elsewhere. On the basis of dependable capacity, 71% is located in Luzon, 15.1% in the Visayas, and 13.9% is located in Mindanao.

Table IV: Concentration Matrix of Power Generation Capacity, By Fuel Type (In Levels and Per Cent)
FUEL TYPE	PHILIPPINES
	Capacity (MW)		Percent Share (%)
	Installed	Dependable	Installed	Dependable
Coal	7,569	7,230	35.0	37.0
Renewable Energy	7,038	6,199	32.5	31.7
Hydro	3,637	3,241	16.8	16.6
Geothermal	1,906	1,752	8.8	9.0
Solar	843	663	3.9	3.4
Wind	427	383	2.0	2.0
Biomass	224	160	1.0	0.8
Oil Based	3,584	2,816	16.6	14.4
Natural Gas	3,431	3,291	15.9	16.8
TOTAL	21,621	19,536	100.0	100.0
Source: Department of Energy website

Table IV excludes off-grid generators.  It indicates that the share of plants classified as coal, geothermal, and natural gas are the dependable ones.  Their percentage share or contribution to the total dependable grid supply is higher than what their installed capacity indicates.

     As in the past, the arrival of power plants into the scene may be described as heuristic or “hit or miss.”  In short, they come almost like accidents that just happen without intelligent design or efficient direction.  However, there is faux pas when there is no power system planning, or study of the impact of a generation plant when injected into the grid or system, the network as a whole.  This is a myriad of a labyrinth, to exaggerate the complexity of electric power.  This is where many would-be developers miserably fail.

     Moreover, there is no one who can lay claim to the fame of being responsible for the present portfolio mix of power plants in the Philippines.

     Ineluctably, there is no escape from the tough reality that a different mix denotes a different accessible price for electricity consumption.  More specifically, possibly lower electricity prices.

Framework’s Areas of Concern

     In crafting the framework bounded by the period from 2018-2029, four important areas of concern have been initially identified. These are the structure of incentives and disincentives, strategic choice that underlies policy, the cost variable, and financial intermediation.  All four are just some of the major areas that determine the success or failure of power generation projects.  It is by way of a national conversation that a well-considered national framework can emerge.

The Structure of Incentives and Disincentives

The structure of incentives and disincentives refers to the total package of benefits and detriments that exist in the present energy milieu.

Under the present structure of incentives and disincentives in the energy sector, and in environment, the power generation industry is surviving well under conditions of perfect competition, in spite of the intense competitive rivalry. Huge funds and capital for construction and operations are being raised and the engines of the industry are running with business success. 

At the end of the risk-taking, returns that are commensurate to the risks are being made; the actualities of business and financial life.  Otherwise, it is expected that investors will shy away.  As the saying goes, “If it isn’t broke, don’t fix it.”

For this area of concern, the underlying policy question is: What sets of incentives and disincentives are necessary to increase installed capacity by 82.10%?

Michael Porter is famous for the principle of being “caught in the middle” of two different generic strategies.  In his framework, those strategies referred to cost leadership, differentiation, and focusing (“niche-ing”).

     Being “caught in the middle” prevents firms from reaping the full benefits that a single-minded strategy has to offer.  Choosing perfect competition market conditions can be likened to a strategic choice which the Philippines prefers over other possible alternatives.  It is important to stick consistently to that strategy chosen, in order not to create discontinuities and to make the playground conducive to doing business.

The Cost Variable

     Cost is always a valid concern for both producers and consumers. Variable cost is a day-to-day concern, but fixed cost is a make-or-break concern.

     Perhaps, the success of the Chinese over the US in doing business is due in no small measure to the fact that whatever their fixed cost is, it can be divided by their population of 1,300,000,000 potential consumers?  Thus, their fixed cost per unit is low; hence, they have a low per unit cost of production.  This phenomenon is explained by the theory behind experience curve pricing. (Go, Josiah. Marketing Mix).

    Quite unfortunately, the Filipinos do not have the advantage of having 1.3 billion people or having a centralized economy completely backed by the might and power of its government’s money.  Instead, it has a handful of entrepreneurs with hard-earned money looking at various possibilities.  Thus, fixed costs in the Philippines are relatively higher, by as much as accountants can justify.  After all, rational businessmen are usually risk-averse.  Not speculators.

     Nevertheless, the least cost criterion is a valid choice provided it is used for the same cross-section.  That is to say, it is time-bound, such that all prices being considered are contemporaneous with each other.  Otherwise, comparison is not merely complicated; it is also odious.

     Least cost along the same cross-section, say, costs from 2018-2023, is a valid criterion.  However, least cost as a methodology of analysis is erroneous when 1998-2003 prices are used for the 2018-2023 scenario.

     Certainly, least cost, as a regulatory strategy, is not plausible when the technologies involved are different (e.g., solar PV versus wind, versus hydropower, renewables versus clean-coal technologies, versus combined-cycle using natural gas or LNG).

     The issue of valid comparisons arises with respect to segmentation with different kinds of energy resources procured.  In as much as technologies change, evolve and progress, and as they do; therefore, orientation and context must change.

     To emphasize, the issue of least cost is just a result of its two component parts: fixed costs and variable costs.  Indeed, this is for further discussion altogether. It is interesting to find out if the differences between the two are considered in regulation-setting.

     Yet, to insist on the least cost criterion is to espouse hydropower that “has been the leading source of renewable energy across the world, accounting for up to 71% of this supply as of 2016.  This capacity was built up in North America and Europe between 1920 and 1970 when thousands of dams were built.  (Emilio F. Moran, et. al., “Sustainable Hydropower in the 21^st century”). Otherwise, is thermal power a disservice to genuine least cost?  However, the least cost criterion misses the point of why people spend. People do not buy just the products or services. Rather, they purchase the entire package of benefits and detriments, also known as “the experience” that those products can deliver. The buyer’s part with their money for products and services that deliver value: that “favourable customer experience.” 

Marginal Cost

Instead of least cost, the more appropriate analytical tool is marginal cost: the cost of acquiring additional capacity within the relevant time period: the present, not the historical past.  As the Nobel laureate economist George Joseph Stigler puts it, “Prices are sticky downward.” (Stigler, “The Theory of Price.”).  Thus, marginal cost pricing. This type of cost refers to the expenses to generate or produce just one more MW of energy.

     When the demand for electricity exceeds supply by, say, 1 kilowatt, the system will keep on tripping every time that the supply is exceeded.  When that happens, there is no way of knowing how many kilowatt hours must be added to the available capacity.  Could it be 1 kilowatt, or 1 MW, or maybe more?  A considerable excess capacity has to be constructed to provide a certain margin of safety to prevent continuing brownouts.

     Thus, the marginal cost of satisfying a 1-kilowatt of shortage can mean constructing an entire 600 MW power plant.  Not at the time of need but way before it happens.  At least five years before it happens, a power plant is indivisible. Half a power plant does not mean half-capacity; it means no additional capacity until the whole hog is running.

     Clearly, the cost that consumers pay cannot be subjected to the least cost criterion. The reason for this is that someone must pay for the margin of safety for the next five years or more.   Indeed, marginal cost is also the cost of preventing future inconvenience, years forward before demand overshoots supply.  Hence, it is an optimal price.

     Thus said, it is important to note that textbooks only deal with the quantitative view of marginal cost.  In the power generation industry, as equally important as quantitative marginal cost is qualitative marginal cost: the question of what to spend marginal cost on. The possibilities can include expensive clean-coal technologies and gas-fired combined-cycle power plants, or even nuclear, assuming that urgency is not at issue. Whatever the choice, each one of them has drawbacks or disadvantages.  Thus, not only is marginal cost paying for the margin of safety in order that power outages are prevented; the marginal cost choice also carries with it the baggage of risks of trading off one power generation possibility versus another.

The Financial Intermediation Variable

     This fourth major area of concern has to do with facilitating the movement of funds from savers to investors.

     Generally, 70% debt and 30% equity reflect the risk complexion facing the power generation industry.  Raising and arranging either debt or equity is already a strenuous undertaking that does not need further aggravation.

     To the point, left alone, the industry is surviving.  Thus, the structure of incentives and disincentives deserves to be maintained because they are proven to work in terms of delivering reliable power supply.

      Over the 2018-2029, recall that the increase in electricity demand and installed capacity are both projected at 82.10%.  For all intents and purposes, a doubling of installed capacity is indicated.

     Where do we go from here: Quo Vadis?

     The Total Quality Management dictum is that customers require Quality, Cost, and Delivery.

     It’s always Quality first.  Stable, predictable, and timely delivery at the moment of need must be met.  And, cost is the last consideration among engineers and management experts. 

     Recently, Board of Investments’ (BOI) November 2018 reports: “Pulangi Hydro Power Corp.’s Php 38 billion project sustained the strong performance of the power sector as it is putting up a 250 MW Hydroelectric Power Plant in Bukidnon.  The manufacturing segment was bolstered by the approval of Petron Corporation’s Php 82 billion investment in the Condensate Processing Complex Project in its refinery in Limay, Bataan; and, the Php 62.6 billion Liquefied National Gas (LNG) terminal project of FGEN LNG Corporation in Batangas City with a capacity of 5 million tons per year. “

     Are these projects successful because the proponents are financially strong?  Do these projects make the industry 5-star in Porter’s paradigm?  No, the resulting rivalry denies the power industry its 5^th star unless players, regulators, and policy-makers in government get together and minimize the effects of that competitive force, maybe, by carving out areas for each of them.

       Coal remains the fuel-of-choice to balance supply and demand in baseload power that propels the country’s newly industrializing economy.  Yet, there is an obtrusive direction to go merchant market, ostensibly backed by the policy of Competitive Selection Process (CSP).  However, CSP impinges on financing that is attuned to the traditional Power Supply Agreement (PSA), the so-called Off-take, that must have a Financial Model depicting a steady Debt-Service Reserve Account, and investment-grade Equity Internal Rate of Return; rather than recurring income, which should be taken more seriously.

     The policy question is: Are banks ready for merchant market?  While the WESM shows stabilizing prices and accessibility to reliable supply, debt-financing for big power plants must have an anchor load that is guaranteed.  This is in spite of the fact that PSAs hitherto do not even require Letters of Credit “for every Anniversary Year” to assure security of repayment. 

     To date, there are a several (around seven) potential power generation projects that are in the pipeline but are encountering setbacks involving the aforementioned areas of concern, in addition to other aggravations.  Apart from the disadvantages inherent in whatever is their respective chosen type of power plant.

Conclusion

     At the end of the day, the nation needs to come to terms with a national agenda on power generation, to have a target mix of power generation units for 2018-2029 that is responsive to the needs of a growing economy. It cannot be overemphasized that a known national portfolio mix of diversified power plants translates to the ability to predict electricity prices within a probable range in the near future.  For sure, that is a prospect that is good both for the producers and the consumers.

     Without injecting value judgments as yet, the Filipino nation needs to come to a consensus on the vision and prospects of power generation from 2018-2029. The stakeholders of the power generation industry must make things happen by targeting this early what kind of energy to produce, how many power plants, for whom to produce, and what type of technology to deploy; again, with due respect to environmental concerns as well as pricing concerns.

     Sadly, on another front, there is a lack of understanding about the dynamics of the Environmental Impact Statement (EIS).  There are anxious concerns on Climate Change.  Do Filipinos appreciate the nuances of carbon emissions, air and water quality?  Is the country’s geology as old as Europe’s vast lands and as ancient as China’s endowed with fossils?

     Or, is the alternative to leave the future to chance, where the framework is inordinate among entrepreneurs, developers, technocrats, regulators, and policy-makers?  Unless a national conversation starts in haste in order to galvanize the nation to move with determination towards a focused, correct direction, energy economics and the country’s power industry need deeper comprehension.

Antonio A. Ver is Charter Founder and elected as the first President of Asia Pacific Basin for Energy Strategies in October 2008, an energy and economic think tank that earned its Special Consultative Status with the United Nations Economic and Social Council (UN ECOSOC) in June 2014 to the present.  He was Independent Director from June 2009 to June 2015 of the Philippine Electricity Market Corporation (PEMC) that runs the Wholesale Electricity Spot Market (WESM).

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