Ramblin’ RECs
Rural Electric Cooperatives in the PHilippines
Selected Opinions on REal Issues
By James A. Nichols, III
Navigant Consulting, Inc.
October 2000
With supporting material and insights
provided by Jose “Viking” Logarta
Introduction
We prepared the observations and opinions found herein over one year ago based on our experiences with joint-action financing in the U.S. and with the Philippine power sector. Many of the issues discussed are still relevant to the Rural Electric Cooperatives (RECs) and even private distribution companies in the Philippines.
In this paper we address:
§ Takeover of 69kV Transmission Assets
§ Commentary on Merger of RECs
§ Implications on Sector Reforms
A companion piece entitled “RECs – A primer” provides insights on the institutions involved in rural electric supply and a brief picture of the relative size and scope of RECs vis-ŕ-vis private utilities and the Manila Electric Company
Take-over of NPC Subtransmission Assets
Over the past several years, NPC has espoused a policy of pursuing opportunities to transfer its subtransmission assets to utilities with franchise to distribute electricity over the areas where the subtransmission facilities are located. In Luzon and most of Mindanao, this means the 69 kV (and below) assets, which are operated radially to serve NPC power delivery points and which are not part of the integrated bulk power network (i.e. they do not serve a production or reliability function to the general network system). In the Visayas grid, the particular assets which NPC might want to divest is not as clear, since the interconnected transmission grid there is operated at 69 kV.
To-date no progress has been made on the transfer of any 69 kV assets to the RECs (or any other distribution utility) and there is currently no substantive activity on-going that will lead to such transfer. The most recently active effort involved negotiations between NPC and the Central Luzon Power Transmission Development Corporation – a private stock corporation registered with the Securities and Exchange Commission and an apparent successor to the Central Luzon Electric Cooperatives Association, an association of RECs in central Luzon. There has been interest expressed by other entities to acquire 69 kV assets from NPC and they have completed various stages of preliminary negotiations with NPC, such as the RECs in northern Luzon in conjunction with Cepalco and the Cebu Electric Cooperatives.
In discussions with NPC, the reason given for no divestiture is simply that no entity has stepped forward with the financial ability to purchase the assets.
NCI reviewed a copy of a proposed Operate-Maintain-Transfer (OMT) Memorandum of Agreement for one such Subtransmission System, which was under negotiation in January 1999 and as provided by NPC. The OMT agreement is, in essence, a simple operations and maintenance (O&M) agreement with a private company (referred to herein as “T-Co”) to operate certain 69kV assets for NPC in exchange for a fee (P0.05/kWh of load served), with an added provision that NPC will sell the assets to T-Co within two years and upon full payment by T-Co at a cost to be determined later but based on either a “net present value method” or an “internal rate of return method”. Neither of these valuation methods[1] is defined any further.
There appear to be numerous flaws in the overall arrangement and concept, any or all which may also be recognized by both T-CO and/or NPC. NCI has had limited or no discussion with the parties. Our comments are provided as a guide to future agreements in an effort to develop commercially viable arrangements.
During the O&M period in the contract, there is no explicit rate recognition of the transaction. It appears that NPC can continue to charge customers served from the 69kV assets an ERB approved rate that is set at any level NPC can justify[2] – so one has to question “what’s in it for the RECs?” The Agreement does contain language to the effect:
“T-CO…may use the system for its own customers. NAPOCOR will grant and permit T-CO the use
of its franchise during the term of the Agreement.”
It is not clear, however, that NPC has the authority to “grant and permit” another entity, especially one that is not a utility, the use of its franchise, nor does it warrant that it can do so. Nor is it clear that T-CO has customers, that it can have customers, nor who they are. If it were the intent of the parties that T-CO get the use of the facilities at the rate of P0.05/kWh on behalf of the subtransmission customers in the area with no additional subtransmission wheeling fees[3] imposed by NPC, then there are further problem areas. Since NPC still owns the assets, the depreciation and return components of their revenue requirements would still need to be met (the P0.05/kWh fee covers only O&M) and if not charged by NPC to the T-CO customers over and above whatever T-CO charges them, then it would have to be subsidized elsewhere.
Other commercial aspects should be closely looked at. For example, there is a bonding requirement for T-CO to perform technically yet there is no bonding requirement backing NPC’s obligation to make timely cash payments. In fact, the whole arrangement may be backwards. If indeed ownership of subtransmission assets is in the best interest of the RECs (an important point examined below), ownership should probably be executed first with an arrangement for NPC-performed O&M under an initial interim contract with the new owners.
If the RECs wish to create an entity to own and operate subtransmission facilities, the approach being taken by T-CO is unlikely to succeed because the entity does not appear to have the underlying security to compete in the capital markets. This is the apparent approach and sequence being taken:
§ Secure a Memorandum of Understanding from NPC to acquire the 69kV assets in a geographic region,
§ secure a technical partner to provide equity financing,
§ obtain a franchise to provide subtransmission service,
§ obtain supplemental debt financing from commercial markets based on equity partner’s participation,
§ acquire the assets,
§ sell wheeling services in the franchise area.
The problem is that the entity being created is essentially a merchant operation – basically because the franchise issued can be revoked or changed into a non-exclusive franchise before a 12-20 year period is up (the necessary debt financing term required for a subtransmission entity).
A suggested alternative approach would be for the subtransmission entity to first obtain long-term, full-requirements contracts with the subtransmission customers in the area to provide their subtransmission wheeling services. This will provide the credit security for the entity to secure possibly 100% debt financing but certainly facilitate both debt and equity sourcing. Even should the entity not achieve an exclusive franchise, the existing customers are tied up and there is an assured revenue stream that lenders can look to in order to partially justify extension of long-term credit.
It may be that the RECs and distribution companies in a geographic area would be hesitant to enter into long-term arrangements with a subtransmission entity unless they had some control over the entity. That is why a non-profit cooperative entity controlled by the RECs and/or distribution utilities themselves is a viable vehicle. However, with the proper contractual commitments, the entity could possibly be a private, stock corporation not controlled by the subtransmission customers but this seems difficult to achieve.
The acquisition of 69 kV assets by the RECs must be re-examined in the context of restructuring. First, restructuring brings open access – at least in principle, if not in practice – and transparent, cost-based wheeling tariffs. Under restructuring, the RECs would purportedly have neither more, nor less, technical and legal access to the utilization of the assets whether they owned them or not. The issue of acquiring NPC direct-served customers on the 69kV system (or serving new large loads from the 69 kV) is likewise irrelevant to the ownership of the assets. Access to the large loads will be competitive, regardless of the owner of the transmission or subtransmission facility. However, to the extent that the RECs can own and operate subtransmission assets less expensively than other entities, and resell the resulting wheeling services to themselves, then they could indeed lower their costs of subtransmission wheeling.
If subtransmission remains in the hands of a government corporation, it is doubtful that the RECs will have access to less expensive capital nor more tax exemptions than the state corporation. However, at some point in the future, privatization of the National Transmission Company is contemplated in the current government-endorsed restructuring plan. Ownership of the subtransmission, therefore, will give the RECs control over their future wheeling costs, regardless of the disposition of the transmission company or the divestment of the subtransmission to other entities.
The concept of control is not to be discounted, especially in a competitive environment. It is a fact that NPC has not adequately maintained certain 69kV assets serving the RECs and NPC cannot operate these assets today to NPC’s own level of reliability or service (voltage) standards. Yet these RECs are paying the same average system wheeling tariffs that that more viable utilities are paying for very good subtransmission service. NPC is simply not responding to the affected REC’s needs nor their own obligations. It is unrealistic to believe that the RECs can compete on a level playing field for large, 69kV customers (or other customers) with such conditions prevailing. One solution is to let the RECs (and other distribution utilities) control their own destiny by creating an environment in which they can make the necessary trade-off decisions on 69kV maintenance and capital expenditures. These decisions are being made today by NPC in light of NPC’s own priorities, not those of the RECs.
Part of the reason why more progress in the cooperative sector toward acquisition of 69kV assets has not been made could be attributable to the following. The process of developing and negotiating the necessary contractual arrangements to achieve REC acquisition of 69kV assets requires the involvement of people with vision, with the persistence to focus on that vision, and with the ability to spend a lot of time in Manila where much of the legal, institutional, and technical consultations and negotiations must be conducted. This is difficult to achieve (especially the latter) throughout the 119 RECs with all of the priorities placed on executive management. Should funding agencies consider 69kV asset acquisition through joint-action an important aspect of the rural electrification program, it is recommended that they consider providing technical assistance to specific REC groups to support this effort.
Commentary on
Merger of RECs
Historically, the argument for mergers and consolidation has been driven by a general notion of scale economies. Our evaluation of the evidence suggests that the expected efficiency gains from reductions in overhead and operations are overestimated.
The problem of viability, in many cases, springs from low demand in the franchise areas, carved on the basis of political boundaries and geography, in the case of the small island RECs. There seems to be confusion of the notion of minimum efficient or economic scales with the strict notion of returns to scale.[4]
Consider, for instance, a franchise area where low demand is the cause of either non-viability or non-competitive tariffs. Merging an REC with another with similar demand characteristics would entail a replication, for a utility with vertically integrated distribution and supply functions, of most of the fixed costs. Though it is undeniable that some of the ‘fixed costs,’ such as management and inventory costs could be spread across a broader output base, we are not sure whether such savings per unit of energy delivered are significant. Our examination of the cost components of tariffs, based on incomplete data, indicate that savings are small. Furthermore, there is no apparent reason why such efficiency gains cannot be captured through innovative joint action mechanisms applicable to inventory and maintenance costs.
There has also been the argument that mergers would automatically lead to improvements in load factors and thus gains in power costs. From a power supply standpoint, this is certainly not the case since the load at the power supply level does not change through mergers of distribution utilities. Even should the RECs achieve conjunctive billing of numerous delivery points, the power suppliers would simply, over time, re-allocate costs over fewer billing units. As to higher utilization of existing assets, there is also probably little gain form merger since there is not significant diversity in peak demand utilization.
The historical experience with mergers also tends to validate our conclusions. In the case of the aborted mergers of five Leyte RECs, the main resistance came from the two better performing ones whose rates would have increased after the merger. In addition, problems with the displacement of labor and other institutional rigidities rendered the whole process unmanageable. Similar difficulties were faced in the merger of RECs in Albay, where any efficiency gains still have to be shown. In the case of the proposed merger of the Cebu REC, it was reported that resistance came from the boards of directors.
What has lent credence to notions of efficiency gains from mergers and consolidation are stylized facts, in scatter plots that show, for instance, that there are efficiencies in capital utilization with increased sales, which is to be expected. However, this is unique within each franchise area. Relative margins, which we define as gross revenue less revenue over power cost, would give a similar misleading indicator of ‘scale economies.’ Efficiencies in the utilization of management and labor are also indicated by plots of operating margins against sales and of connections per employee against connections. (See Annex 5).
A form of equity argument has also been forwarded. To the extent that high operating margins per kilowatt-hour are associated with low sales and sales per connection (See Figure 13), in turn linked to low per capita incomes in the franchise areas (thus poorer households tend to face higher rates, except in Mindanao compared to the rest of the country), mergers can be an indirect but crude redistributional tool, in which case the cooperative ‘spirit’ has to be invoked to execute a zero-sum exercise. That proposed mergers of this nature have been resisted by the potential losers indicates that this spirit is weak.
Figure 13
It is no wonder then that as of this writing, no division within the NEA is seriously studying potential mergers. It is also not surprising that earlier versions of the power restructuring bill, in the past administration, eventually fell silent on the issue.
Implications of Sector Reforms on the RECS and NEA
The overall thrust of the power sector restructuring is to introduce market forces into the framework for managing the electricity sector in order to lower rates. This is first being introduced at the generation supply level. Another major component is the introduction of direct retail access. Even in the regulatory arena, the government’s supported restructuring bill endorses alternative regulatory mechanisms to rate-base regulation such as consideration of performance-based mechanisms.
Lowering rates for the majority of retail electricity consumers throughout the country is the overall purpose. The RECs are a major retail segment – the purpose of restructuring is not meant to apply to everyone but the RECs. One can argue, therefore, that the focus of REC (or rural electrification) initiatives over the next few years must be on developing market-competitive electric service – whether it be in densely-populated areas or far-flung, non-grid connected areas.
In a restructured environment, a clear delineation must be made between the conduct of missionary electrification (subsidized by the national government) and the provision of competitive electric service. RECs do not have a sole mission to conduct missionary electrification. They will have, in the restructured sector, a dual mission – provide competitive electric service and conduct missionary electrification. The IOUs have a similar mission but the level of missionary electrification in their franchise areas is such that it does not jeopardize their business to the extent it does for most RECs[5]. The challenge is to define regulatory and financing methods that will allow the RECs to conduct a dual role – it can be no other way, for whatever type of entity has the franchise in these areas will face the same dual dilemma.
Power Supply Issues
NPC’s historic statutory obligation to provide power supply to the RECs carried with it absolute command of the generation market. This has been only minutely mitigated by the introduction of IPPs. If the benefits of competition in the production sector are to reach the RECs, they must be able to access that market in the same way that Meralco and the IOUs access that market. As discussed below, it is not known how NPC will assign (or if they will assign) multi-year power supply contracts among the “gencos” and residual IPPs to their existing customer base, but the method must not put the RECs at a disadvantage in timely access to a competitive market.
For the major interconnected grids, a spot power market will be operated which will be accessible by qualified distributors. It is fully expected that there will be financial and credit qualifications for participating in the power pool and not all RECs may meet the yet-to-be-defined credit qualifications. HB 4579 provides an expanded role for NEA to act as a guarantor for purchases of electricity in the wholesale spot market by RECs and small distribution companies to support their credit standing.
The bulk power market will operate through both bi-lateral contracts as well as the spot market. It is expected that, at least initially, most bulk power energy transactions will take place through bilateral contracts – such as the Meralco contracts with First Gas Holdings (1500 MW) and Quezon Power (400 MW) and other utility contracts such as the East Asia Power Development Corporation contracts with Visayan Electric Company and the Mactan Export Processing Zone. It is not yet determined exactly how the “gencos” and the residual IPP contracts with NPC will interact with the power market. Should the privatization plan include an assignment of bilateral power sales agreements between the gencos/residual IPPs and the existing NPC market, then the RECs could end up with bilateral contracts for the supply of their power requirements over a multi-year period. Such contracts could possibly “freeze” the RECs out of the competitive bulk power market for some period of time. It is recommended that further investigation be conducted directly with NPC on planned or possible REC power supply scenarios.
Should the RECs be put in a position of securing their own power supply through their own decision of participating solely in the spot market or a combination spot market and securing of bilateral contracts, further work needs to be conducted related to investigating and defining how the RECs will participate in the bulk power market.
Today, RECs have the option to pursue bulk power supply options from independent power producers (IPPs) as an alternative to or supplement to their NPC supply. However, to date, such pursuit has been conducted on an individual REC basis and several power purchase agreements have been entered into. The majority of these arrangements involve diesel-fired plants that initially operated in the 10-15 MW range (the average REC is about 12 MW peak demand). It is very difficult to attract foreign equity capital for projects much less than 12-25 MW (the transaction costs simply are too large a percentage of the overall project to make them easily feasible for smaller sizes). Diesel-fired projects can be economically feasible only when operated in a base-load mode. The base load of an individual REC rarely exceeds much more than about 40% of its peak demand. Therefore the opportunities for developing base-load projects on an individual REC basis is very limited.
The RECs must be able to aggressively exploit the competitive market for generation services on behalf of consumers who choose to remain with them as a utility. If the RECs are to competitively compete in the bulk power market, some type of joint-action may be required such that a single entity can enter into a bulk power arrangement on behalf of a number of smaller RECs. The most important credit aspect to the successful development of a bulk power project is the underlying revenue base of the entity financing the project. The individual REC franchise is the critical key and this franchise should be translated to the joint-action agency through long-term, full-requirements power purchaser agreements with the joint-action agency. However, retail open-access (depending on the threshold level down to which it is implemented) can erode the power supply value of this franchise[6] and further analysis should be given to modes of participation in the power supply market.
Distribution Operation Issues
Retail competition and the threat of losing customers is at the core of the RECs concerns with sector restructuring. However, this is exactly what drives the restructuring concept. At some point, cross-subsidizing residential and missionary service from industrial customers becomes self-defeating and the lowering of industrial tariffs can create profitable load growth that better utilizes the investment in assets. There is financial risk in the transition and this must be mitigated by the ERB in granting consumers choice gradually. But the RECs must take advantage of the transition period to prepare to compete.
The RECs must be given the ability to tailor electric service to the needs of the customers. The concept of one size fits all will no longer work. This means, in one respect, that substantial work needs to be done in retail pricing research and studies (rate design, if you will). Substantial institutional strengthening will be required in this area.
There are many components of retail electric service, such as the purchase of bulk electricity, metering and information systems, energy efficiency services, pricing and billing options, and reliability and load management options. This even applies to non-grid connected areas where new and renewable technologies can possibly be used and priced at commercially viable rates to meet the needs of the community. In a competitive retail market, each of these components can be tailored to increase consumer satisfaction.
The RECs will need to be able to adaptively and pro-actively address changes and innovations in these areas – but it may not necessarily be to the same extent across all RECs. The RECs serving more urban areas will need to meet the challenges in a different way and possibly to a different extent than isolated, rural areas. The rural electrification program, therefore, must provide a technical assistance and institutional strengthening framework that also is not a one-size fits all approach anymore.
Direct access can, in the end, benefit the rural consumers (if not the existing REC organization serving them) – that is, consumers that stay with the REC as a retail supplier. In order to remain competitive, the REC will have to procure and deliver power in a least-cost manner. If the REC fails to do so, it risks losing consumers and market share to suppliers who better meet their needs. To the extent that direct access does not extend to the individual rural consumers, the same competitive pressure can be brought by exposing the REC to the risk of buy-out by a private utility or entity.
It is just this risk that can vitalize the sector and provide adequate incentive to management and Boards to increase the value of service provided to the member-consumers. It is just this risk that could create the incentive (out of self-preservation) for self-initiated mergers where there are, in reality, efficiencies to be gained. It is just this risk that could provide the drive to create joint-action efforts among RECs that make sense in the Philippine context.
In order to make the buy-out threat real, certain equity issues need to be clarified so that the market knows what it is dealing with. Generally, in a non-stock cooperative corporation such as the Philippine RECs, one would expect that the equity of the organization lies completely with the consumer-members and is founded on their contributions, through rates, to net margins over cost (all net margins contribute to equity) as well as the membership fees. However, the issue in the Philippines is less clear and additional work needs to be done to clarify (with stated government policy) who has an equity claim on the corporation and precisely how it is to be determined. For example, the national government (through the legislature possibly) could claim that the historical subsidies (and any debt condonation) provided to the RECs provide it with an equity claim. Similarly, NEA itself could claim an equity share.
The RECs must be prepared for the restructured, competitive market. There needs to be a transition period during which certain institutional strengthening, public awareness, and other transition activities can take place. For example, already mentioned has been the need for pricing studies, development of variations in service options, and the exploration of mechanisms for competitive bulk supply. There needs to be work in defining alternative and multiple financing mechanisms for the RECs.
It also seems that a necessary part of this preparatory, transition to competitive electric markets may entail certain changes in the statutory authority of NEA over the RECs and in NEA’s policies with the RECs. There were good reasons in the past for NEA’s statutory authority and policy guidelines (such as those relating to tariffs and operating standards) in order to protect the government’s interest in the assets acquired through national debt. However, restructuring may require a new pact.
For example, in a competitive environment the utility must be in a position to understand the variations in consumer value (different reliability needs, different supply characteristic needs) and to be flexible enough to provide it in a timely manner. It seems impossible that NEA, a central organization with centrally determined service standards, to be as in-tune with the market needs (and be able to act quickly enough) to allow the RECs the flexibility they need to compete. It also seems that if the Boards and management, and consumer-members who elect the Boards, are to be adequately susceptible to market pressures, they must be adequately susceptible to the consequences and opportunities.
The need for decentralized management and mobilization of local populations[7] goes to the heart of the Philippine cooperative concept – it is the precise reason the cooperative model was selected in the first place to electrify the countryside. It was recognized over twenty-five years ago that a centralized, Manila-based entity was not a feasible option for organizing and building the RECs. Over the intervening years, NEA’s centralized intervention over the RECs has increased significantly (for good reasons such as technical support, combating unduly politicized Board situations and local REC corruption). Sector restructuring, however, also signals the need for rapid response to local population needs and the need for, and extent of, local control should be revisited in light of changed circumstances.
The statutory authority of NEA over the RECs should first be studied closely for recommended changes to address the restructured environment. After those are determined, NEA and the RECs need to review the existing policy manuals and directives in place which conflict with those new authorities or which need to be modified to accommodate competition.
For the debate to be adequately held regarding possible buy-out, the consumer-members must also be adequately knowledgeable of the cooperative concept and their rights and obligations under it. It is the responsibility of the rural electrification sector (through NEA, PhilRECA, and the RECs themselves) to conduct aggressive campaigns to get their points across about the benefits of the cooperative structure.