Reliability of Philippine Power Systems

Reliability of power systems define the utility's capability to minimize outage frequency and duration. For regulatory purposes, power system reliability indices are evaluated for performance based regulation (PBR). In the Philippines three performance indicators on system reliability are among the indices evaluated to assess transmission and distribution electric systems for regulatory years involved. System Average Interruption Frequency Index (SAIFI), System Average Interruption Duration Index (SAIDI) and Customer Average Interruption Duration Index (CAIDI) are the indices required by Energy Regulatory Commission (ERC) from the utilities and whose formulas are given below. The data presented herein are acquired from the ERC website and from the National Electrification Administration (NEA) website.

The transmission electric system reliability performance are provided below in the following two figures. The first five years show separated indices for the three regions while the next five years show combined transmission performance for the whole nation. It is revealed from the figures that transmission system SAIFI and SAIDI are lower for the last five years which indicate that outage frequency and duration were minimized in the bulk power system.

The next three figures illustrate the reliability performance of four Distribution Utilities (DUs) in Mindanao. The SAIDI presented here are said to be "Planned" SAIDI, which I assume incurred during scheduled maintenance outages of the DUs. For SAIFI and SAIDI, Cotabato Light and Power Company, Inc. (CLPC) performs better than the other DUs. For CAIDI, Mactan Electric Company, Incorporated (MECO) and Cagayan Electric Power and Light Co., Inc. (CEPALCO) provides minimum customer outage duration. What is interesting is that MECO and CEPALCO reported the same CAIDI values for different four year intervals. The CAIDI formula above does not apply to the CAIDI values as the SAIDI are "Planned". The DU reliability assessment here does not consider the GWh sales and number of customers served of the DU which I believe has an impact to the DU reliability performance. This kind of evaluation is slated in the upcoming articles.

NEA reports a reliability criteria for Electric Cooperatives (ECs). The highest score for this aspect is 5.0 as defined by NEA, which is not reported in their website. Figure below shows that at least four ECs perform up to the par of the NEA reliability criteria.

Demand-Side Management Practices

The electric power system as driven by economic market forces experiences intensive utilization. To keep electric power systems continue to operate in a reliable and secured manner, resources aside from power generation are needed. Demand-side management has been taking its place in supporting power system operations and planning in the deregulated era. Significant reliability and financial benefits are derived in utilizing various forms of demand-side control.

Demand-side management or control types can be categorized in the order of contribution to power system security and electricity market efficiency.

• Time of Use Pricing (TOU) - this approach shifts power consumption from peak periods where the probability of high market prices and transmission congestion are obviously high and expected.

• Real Time Pricing (RTP) - this demand-side control strategy allows the load to reallocate energy utilization to lower market price hours and when power transmission usage is lower.

• Demand-side Bidding - this category assist the system operator for maintaining generation-load balance and in managing of zonal congestion. With this, it tends to lower the operating cost of the consumer and demand-side assists in alleviating generation resources shortage.

• Demand-side as Ancillary Services - demand-side is utilized as system reserves through emergencies especially when no other possible option provides solution to mitigate existing system-wide operating concerns. In this case, demand-side can be called to support the system operation as Responsive Reserve, Non-spinning Reserve, Regulating Reserve, or as a Replacement Reserve. Most often, the demand is reduced during periods of critical generation reserve margins and when electricity market prices are high due to generation shortage.

• Direct Load Control - this strategy employ the usage of automated control to reduce or curtail demand consumption during the occurrence of price spikes or during summer periods.

• Interruptible Load Program (ILP) - demand is reduced or cut-off from the grid to maintain secured system operation during emergencies where system continuous service can be put at risk. Some system operators utilize interruptible load for economic benefits and eliminating system operating constraints.