The Controversial DOE Competitive Selection Process Requirement

A recent article about the energy sector caught my attention. In the article, it said that many Distribution Utilities (DUs) especially Electric Cooperatives (ECs) have filed exceptions from adhering to the mandated Competitive Selection Process (CSP) requirement. And in response, the Energy Regulatory Commission (ERC) has said that DUs that have already “negotiated, executed and signed but not filed prior to November 6,” can execute said contracts without the CSP, but rather must undergo a SWISS challenge to ensure fair competition.

Confusing, isn’t it? But confusion is exactly what comes to mind when energy players talk about the CSP. What’s even more mind-boggling is the inconsistencies between the CSP version of the Department of Energy (DOE) and the ERC’s implementing guidelines released last November, which kicked-off the implementation of this scheme.

To recall, shortly before Jericho Petilla left his post as Secretary, he signed a DOE Department Circular requiring all DUs to undergo a competitive selection process or CSP when procuring their power sales contracts. Curiously, the CSP should be conducted – not by the DUs themselves, who will be directly affected by such contracts – but by a Third Party.

Under this CSP Circular, DUs are required to aggregate their un-contracted demand requirements, which will then be bid out by the Third Party. Simply put, under the CSP Circular, DUs can no longer procure their power supply on their own, either through bidding or direct negotiation with power suppliers. On the surface, this looks like it is a good move to ensure a process that will yield the best results for the consumers.

This CSP Circular has caused a stir and is still causing a stir among energy players for a variety of reasons. Industry players are concerned about the undesirable effects on the DUs and their customers, the difficulty of its implementation, as well as the legality of the CSP Circular. Allow me to discuss some of the concerns of energy players like myself about this widely discussed and highly controversial Circular.

Many question the underlying lack of trust of the DOE on the DUs, which is made apparent by DOE’s assigning a Third Party – instead of the DUs – to procure power for electricity consumers. The EPIRA mandates that the DUs enter bilateral contracts to purchase the power they provide to their customers. DUs have been doing this ever since. In removing this duty from the DUs and handing it over to an unknown Third Party, the message sent is that the government believes the DUs are incapable of serving the needs of its customers.

To reiterate, the CSP Circular restricts the DUs’ ability to procure power by requiring that procurement could be made only by a Third Party. It effectively prohibits a DU to procure power on its own.

This new requirement begs the following questions: Why create a new animal (i.e., Third Party) to do what DUs are mandated to do and are capable of doing? Is DOE not adding an unnecessary layer in supply procurement by creating an unnecessary entity instead of strengthening the regulatory power of the ERC and National Electrification Authority (NEA) over DUs and electric cooperatives, if only to better enable them to procure power wisely? Why burden the already burdened electricity consumers with the additional costs of the Third Party when the necessity for such entity has to be established? Why require a Third Party to bid, negotiate, and even to draft power supply contracts, on behalf of the DUs when efforts could be exerted to strengthen the capabilities of the DUs for supply procurement (assuming the DUs are indeed incapable to begin with)?

Ironically, while the CSP Circular makes the Third Party an indispensable party – without which DUs would not be able to procure power – a Third Party incurs no liability whatsoever under the Circular. It behooves one to ask: What will happen if the Third Party fails to secure power supply? What happens if the CSP fails? Should electricity consumers be left empty handed with no power supply, but still obligated to pay the Third Party’s fees?

The CSP Circular appears to debilitate the DUs, to the detriment of the consumers. Again, who else are in a better position to know the requirements of the DUs than the DUs themselves? Certainly not an unknown Third Party.

Many also question the CSP Circular’s inability to be responsive to the needs of consumers. Under the Circular, for a DU to obtain power supply, it must wait out the long process consisting of the selection of the Third Party, the aggregation of its demand with other DUs and finally, the lengthy bidding procedure. Thus, the Circular takes away from DUs the option to immediately contract power to address urgently power shortage or emergencies. A DU that is in need of urgent power supply would have to wait for the Third Party to go through the whole process. It will take many months, even years, to get finally get supply. In the meantime, electricity customers would have to suffer from blackouts or power interruptions, and worse, to pay for higher costs of electricity. Without enough contracted supply, the DUs are most likely to buy power from the spot market despite higher prices to provide its customers with power. In the end, the consumers will suffer from regular power interruptions and end up paying for higher electricity. Without the CSP Circular, DUs can readily contract from an emergency power supply.

Many also see the CSP Circular as favoring the bigger power players and hurting the smaller ones as well as renewable energy (RE) developers.
Contracting based on aggregated demand results in the bidding of large capacity. Only the large power companies – and there are only a few – who can finance power plants with large capacities. So, how can smaller players go head-to-head in bidding for the aggregated demand? In the same vein, RE plants, generally, have a relatively small capacity. Since RE plants will not be able to bid for large aggregated demand, further growth of renewable energy will be stunted.

To illustrate this point more clearly, let us say there are two power suppliers, with one capable of supplying 300 megawatts and another capable of supplying only supply 30 megawatts. What will be the expected result of a bid process if the demand up for bidding is 250 megawatts? Generation facilities with small capacities will be excluded from the bid.

All told, now that DUs are required to aggregate their demand, it is expected that small power players and RE plants would be at a huge disadvantage against big power companies and conventional technologies. Given these, it is no wonder many criticize the CSP Circular as running counter to the essence of the EPIRA, which espouses open competition and broadening the ownership base in the generation sector, to bring power rates down.

From a legal standpoint, the CSP Circular violates the franchise rights of the DUs. Lawyers who shared their legal opinion on the matter with me stressed that denying the DUs of their right to enter power supply contracts on their own is a clear violation of their franchise rights to procure power supply for its franchise area. The DUs’ right and mandate to procure supply cannot be lawfully delegated to another entity with no such mandate, such as the Third Party. DUs are public utilities whose franchise rights were granted by the Congress, and only Congress has the power to amend said franchise rights, according to lawyers.

Many are likewise concerned that the effect of demand aggregation would be unfair to the captive market of each DU.
For example, two DUs are grouped together and win the aggregated demand. The first one makes use mostly of baseload power supply while the other one uses a more peaking power supply, which is far more expensive than baseload. This means that the DU using more baseload power will have lower rates compared to the DU that uses more peaking power. If both are aggregated into one contract, then consumers of the both DUs will have to share one tariff applicable to both. The consumers of the DU that uses the baseload plants with the lower tariff will end up paying more, thereby subsidizing the higher tariff of the other DU. This results in what is called cross-subsidization, which is prohibited under the EPIRA.

Needless to say, the CSP Circular is causing a lot of concern in the power industry, as many of these critical questions remain unanswered. Further complicating this, the ERC recently issued rules requiring DUs to conduct bidding, but without a Third Party as a form of compliance to the CSP. The ERC rules on CSP did not adopt the guidelines of DOE’s circular. This was after much-publicized coordination with the DOE on the implementation of the CSP Circular. As one would expect, DUs are now confused on how they can contract for power supply.

Of course, the DOE must have had good intentions when it came out with the CSP Circular. However, one cannot deny that there is so much uncertainty as to its necessity, legality, and effectiveness. Isn’t it more prudent to share a comprehensive study on the feasibility and legality of a Third Party-managed bidding for aggregated demand to all concerned before its implementation? Doesn’t prudence also dictate that the CSP requirement using a Third Party be made optional rather than mandatory? At any rate, it is best for both the ERC and DOE to thresh out the details of the CSP, and end the confusion for the benefit of all.

CAPM and Geothermal Energy Projects in the Philippines

Aside from the relatively high cost of developing geothermal energy sources, there is another challenge that the private sector deals with in developing the said renewable energy in the country: regulatory challenges, particularly the tariff setting mechanism.

CAPM Formula. Photo from www.money-market-trading.com

CAPM Formula.
Photo from http://www.money-market-trading.com

In my previous post, I have discussed the Capital Asset Pricing Model (CAPM). The CAPM assumes that investors will choose the assets that will yield higher returns over risk-free assets that provide a premium. The CAPM developers used Beta to measure the premium for the risk of an asset, assuming that using the entire market can reflect accurately the correct return of the risk of a particular asset

The Energy Regulatory Commission or ERC uses the CAPM in the tariff setting scheme.

Under the CAPM, the cost of equity is calculated based on the following formula and parameters:

re =rf + betae x MRP

where:

re = nominal cost of equity

rf = risk free rate for the Philippines

betae= the equity beta for benchmark generation company

MRP= Market Risk Premium (MRP)

Both the risk- free rate and market risk premium are based on the historical ERC approvals.

However, the ERC reportedly uses the same beta of (~1.03) for the tariff setting of power plant projects regardless of the technology without consideration to the risk profile of the power plant project. This means that the value of Beta is the same for coal power plants and geothermal power plants. And here lies the problem.

Using the same beta for coal-fired power plants for cost recovery is unfair to geothermal developers and does not reflect the proper conceptual use of the CAPM.

Let’s look at the case of two power plant projects—a geothermal and a coal-fired power plant.

The ERC approved a coal-fired power plant project of 110 megawatts in Mindanao. Its total project cost is roughly P14.6 billion.

The ERC also approved a 40-megawatt geothermal power plant with a total project cost of more than $207 million dollars or roughly P9.1 billion pesos. (at $1=P44 Exchange Rate).

Both projects are financed by 70 percent from loans and 30 percent through equity.

In our above examples, it is obvious that geothermal power plant project costs more. The coal-fired power plant has a capacity of 110 megawatts and costs P14.6 billion, whereas the geothermal project has 40 megawatts capacity but costs around P9.1 billion.

Of course, the costs of geothermal exploration and power plant construction are higher than putting up a coal-fired power plant. But, again, it is wise to invest in geothermal energy since it is not subject to price fluctuations, unlike fossil fuel-based plants.

As mentioned in my previous post, the private sector undertakes high risks because of the exploration required to develop the geothermal sources. Geothermal power projects entail exploration including the drilling of wells to determine if steam is available. Test drilling alone can cost $5 million per hole, and there is no guarantee that steam is available from the hole being explored.

In fact, according to a study conducted by the International Finance Corporation, roughly only 60 percent of the explored holes worldwide turned out to be successful.  This means that geothermal exploration is a high-risk and expensive undertaking. Exploration alone costs more than half of the total project cost for geothermal power plant projects.

On the other hand, coal-fired power plants only require the importation of the fuel and the power plants structures that are almost uniform.

The ERC uses the beta for coal (~1.03) to determine the return on equity for any project regardless of the risk profile.

Arguably, ERC’s choice of using the same Beta for coal and all other power projects is an incorrect application of the CAPM. Plus, of course, it is most unfair for renewable energy developers especially for geothermal energy developers in the country because they bear risks that are higher compared to the risks undertaken by coal-fired power plant owners.

The Beta in the CAPM, again, measures the risk. It follows that an asset, which has a higher risk profile, should have a higher Beta value. Under the CAPM, the riskier the asset is, the farther the asset is from having a Beta that equals to 1. Simply put, the value of the Beta used for the computation of the tariff should reflect the specific risks assumed by that particular asset in relation to the entire market.

The value of the Beta should reflect the risk of the market since CAPM assumes that the entire market can reflect the correct return of the risk of a certain asset. It is then sensible to use a Beta that reflects the premium for the specific risk of investing in a geothermal energy power project in relation to the entire market rather than a Beta for a different type of asset or technology, in this case, the coal-fired power plant.

It is therefore, logical that a geothermal energy power project will have a different value for the Beta, a higher value at that since geothermal development is riskier than a coal-fired power plant project.

The geothermal power plant projects should be given a higher yield than coal-fired power plant given the higher capital and risk exposure of the private developers. This is especially true these days where the government no longer shells out money for the exploration, but rather leaves the private sector to do its own exploration of geothermal sources, which comes at a high price.

Unfortunately, the ERC does not see it this way as it uses the same Beta for all power plant projects.

So, what incentives do geothermal power plant producers have to invest their money on such a risky undertaking when they are unable to obtain the required return given the incorrect valuation of the risks involved in these projects?