by Antonio A. Ver[1]
November 19, 2018
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) | |||
| Year | Peak Demand | 5.6% Annual Increase | Cumulative 5.6% 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
For the record, the structure of incentives and disincentives refers to the total package of benefits and detriments that exist in the present energy milieu. As everyone knows, there are benefits (tax breaks, etc.) and regulations existing in the environment that make it rewarding, at times, and inconvenient, at times, to be in the power generation industry.
As everyone expects, the structure of incentives and the structure of disincentives taken as one structure, is an area of concern that should be first on the agenda of the national conversation. Definitely, the rewards must justify the risks. Or, no risks need be taken by those who are risk-averse. At the end of the risk-taking, it is only fair that returns commensurate to the risks are being made. That is a hard reality of business and financial life. Otherwise, it is expected that investors will shy away. With the kind of money involved running into billions of US dollars, everyone must tread lightly, so as the saying goes, “If it ain’t broke, don’t fix it.”
Without dwelling into the details for now, industry insiders are fully aware of presently existing projects whose operations are in suspense because of regulatory difficulties. Eventually, the entrepreneurs and the public must bear the costs of such delays. On the side of the entrepreneurs, they still have to make good on the loan amortizations, even if that means borrowing more. Whatever happens, the consumers end up footing the bill later, since those costs (next agendum) will be passed-on to no one else but them.
Under the present structure of incentives and disincentives in the energy sector, and in environment, the power generation industry is still surviving well under conditions of perfect competition, in spite of the intense competitive rivalry. In view of the achievement and business strides that must be made, it is fortunate that huge funds and capital for construction and operations are continually still being raised and the engines of the industry are running with business success.
For this first agendum, the underlying policy question is: What sets of incentives and disincentives are necessary to increase installed capacity by 82.10%?
The Strategy That Underlies Policy
For the second agendum, it is about strategy that underlies policy.
In brief recall, Michael Porter is famous for the principle of being “caught in the middle” of two different generic strategies. In his framework, those (generic) strategies include cost leadership, differentiation, and focusing (“niche-ing”).
In the Porter framework, being “caught in the middle” prevents firms from reaping the full benefits that a single-minded strategy has to offer.
At least in the power generation business, the rules of the game arising out of policies hew as close as possible to perfect competition. Thus, the continuing development of increasingly perfect competition market conditions can be likened to a strategic choice which the power generation players prefer over other possible alternatives. It is important to stick consistently to that strategy chosen, to make the playground conducive to doing business and in order not to create discontinuities.
But first and foremost, so what is the national strategy that the players can feed on in the national journey towards increasing power generation by 82.10% from 2018-2029? If there is one, it has to rise to the level of making things happen.
In other countries, their governments provide subsidies and funding support. For power plant entrepreneurs and developers in the Philippines looking at a period of expansion in demand from 2018-2029, the game could be perfect competition in a free market. All is fair.
However, there are opinions that too much regulation stifles free markets. It delays cash flows and the expansion of the industry. It increases the costs of doing businesses. Ultimately, those costs get passed-on to consumers.
In short, the structure of disincentives needs to be crafted within the same overarching objective that the structure of incentives is crafted. To increase power generation capacity by 82.10% from 2018-2029 is not an 11-year undertaking. The five years required to erect dependable power plants impel everyone to look at the 11 years less five.
The Cost Variable
The third agendum in the national conversation is the cost variable. As always, cost is a valid concern for both ends of the market: the producers and the consumers.
Quite briefly, there are three sub-areas of concern here: variable cost, fixed cost, and marginal cost.
The first one, variable cost varies with output. For instance, fuel cost. Enough has been said about fuel cost as the culprit to blame for high electricity prices. Until fuel prices fell and the prices of electricity stubbornly refuse to leave the old neighbourhood.
The second one, fixed cost does not vary with output. Like the cost of the plant, the salaries of the workers, and the amortizations to the bankers. They have to be paid on time until hell freezes over. After all, a business is forever.
In retrospect, 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. With billions involved just to enter the industry, they are not speculators. No one can afford to recklessly lose money in the power generation business.
The third one, marginal cost refers to the expenses involved to achieve increasing generating capacity by 1 MW or by 1% or 82.10%. At the end of 2029, this is the kind of summative cost that matters and the yoke around the Filipino nation to be borne by them from that time. How much money per kW after the 82.10% increase in generation capacity? It is drivel talk to avoid answering this kind of question.
Of late, the dust fails to clear. It will never clear by itself alone. Until that last simple but devastating question gets answered. And then, enter the motherhood statement called the “least cost” criterion. It looks like a total stab in the dark. 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 different times are involved, say 2018 versus 2020 versus 2025 versus 2029.
Certainly, least cost, as a regulatory strategy, is definitely 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).
Interestingly, the issue of valid comparisons arises with respect to segmentation with different kinds of energy resources procured. Inasmuch as technologies change, evolve and decay, 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, in a national conversation. 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 21st 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 buyers’ part with their money for products and services that deliver value: that “favourable customer experience.” That brings us back to dependability with only coal, geothermal, and natural gas power plants as the dependable ones. (Infra. Table IV, p5). So, what is their share in the power generation mix at the end of 2018-2029? How do we get there?
Marginal Cost
Since dependable power plants take time to build, what is started in 2018 can be expected to operate by 2022-2023 yet. By the same token, the last plant to start operating by 2029 has to start construction by 2024-2025, barring unforeseen circumstances.
In the power generation business, there are rarely any surprises. No novice is expected to be able to conceptualize a power plant, especially a big one, to put everything together, and make it run.
With billions at stake, it takes a bunch of rich fools to even bravely attempt joining the industry. It takes foresight, some call it vision, the sight of a power plant already running in the entrepreneur’s mind even what are in front of him are just designs and financial plans.
In that manner, industry players know when someone is playing the game of “bluff.” Like, there is not even a range of firm target prices for electricity from 2018-2029.
Quite appropriately, the policy guideline 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).
Analytically, the precise tool is marginal cost pricing. This type of cost refers to the expenses to generate or produce just one more MW of energy, across 2018-2029 and beyond.
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 outages.
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. Thus, it is an optimal price. Undeniably, there are constraints. By force of circumstances, dependability is important. To patronize the engineering profession, cost is the last consideration.
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. In this respect, the third agendum in the national conversation is financial intermediation, which means “financing,” or, “to make funds available.”
Generally, the financing outlook is 70% debt and 30% equity. That reflects the risk-sharing facing the power generation industry. Already, raising and arranging either debt or equity is a strenuous undertaking that does not need further aggravation.
In spite of it all, albeit left alone, the industry is surviving. Thus, the structure of incentives deserves to be maintained because they are proven to work in terms of delivering dependable power supply. On the other hand, the structure of disincentives (and regulations) that make it hard to build more power plants deserves attenuation.
Where do we go from here? Quo Vadis?
As Total Quality Management practitioners insist, customers require Quality, Cost, and Delivery.
However, 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 Php38 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 Php82 billion investment in the Condensate Processing Complex Project in its refinery in Limay, Bataan; and, the Php62.6 billion Liquefied National Gas (LNG) terminal project of FGEN LNG Corporation in Batangas City with a capacity of 5 million tons per year. “
Curiously, 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 5th 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.
Against all odds, 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 (DSRA) and investment-grade Equity Internal Rate of Return (EIRR),” rather than correctly analysing recurring income.
Perforce, the policy question is: Are banks ready for merchant market? While the Wholesale Electricity Spot Market (WESM) shows stabilizing prices and accessibility to reliable supply, debt-financing for big power plants must have 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 (at least 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.
Admittedly, the agenda for the national conversation are bare bones. They are neither complete nor comprehensive. Thus, they make room for improvements and the development of a truly national framework on power generation.
In a graphical sense, as the power generation industry players reach out for the fruit of honest venture, they are aided by the sticks of financial intermediation while they must carefully step on the structure of incentives and disincentives. The distance that separates the players from the fruit are the costs of doing business.
In no uncertain terms, 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. including the local government jurisdictions where the power plants are situated.
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 seems to be a lack of understanding about the dynamics of the Environmental Impact Statement (EIS). For quite some time now, there are anxious concerns on Climate Change. But, do Filipinos appreciate the nuances of carbon emissions, air and water quality? And, is the country’s geology as old as Europe’s vast lands and as ancient as China’s endowed with fossils?
Unless a national conversation starts in earnest in order to galvanize the nation to move with determination towards a focused, correct direction, energy economics and the country’s power industry is expected to amble gingerly in the search for the grail of deeper comprehension.
This article was also published in Inquirer.net last November 19, 2018.
[1] 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).
