amounts (in some cases more than 50 percent becomes reduced demand when those users have to pay for that electricity, because they adjust their consumption to their ability to pay for electricity services. The reduction in demand has exactly the same effect as a reduction in technical losses, less electricity needs to be generated. Thus, from the country’s perspective, reductions in non-technical losses are also positive. From a social point of view, non-technical losses have several perverse effects. Customers being billed for accurately measured consumption and regularly paying their bills are subsidizing those users who do not pay for electricity consumption. There is a wide range of situations creating non-technical losses. A classic case is a theft of electricity through an illegal connection to the grid or tampering of a consumption meter. But examples also include unmetered consumption by utility customers who are not accurately metered for a variety of reasons. In all the cases some level of poor management of the utility in execution of operations is present.
Electricity theft is default subsidization of those who steal by customer regularly paying bills according to their consumption. The same usually applies in the case of unmetered customers, unless this situation is explicitly and transparently defined by the competent authorities and reflected in the legal and regulatory framework of the sector. In some countries some categories of consumers (e.g. agriculture users, in India and Bangladesh even in Nigeria) are unmetered and pay a fixed amount for electricity irrespective of the amounts consumed, which means in practice that they are subsidized by consumers in other categories, tax payers or both. Depending on the financial situation of the power sector, the savings from reductions in non-technical losses could be channeled to
1. Reduce tax payers subsidies or tariffs paid by customers,
2. Achieve an average tariff level allowing recovery of costs reflecting efficient sustainable performance (critical to assure service quality),
3. Subsidize consumption of selected categories of social sensitive existing users, or
4. Extend access to electricity supply to currently unserved population (in general the
poorest and socially unprotected).
2.4 System Reliability Modeling
System reliability models are able to predict expected customer interruption statistic from component reliability data, system topology, and operational assumptions. Many of the references listed in Appendix A address system reliability modeling, but basic functionality already exists in most commercially available feeder analysis packages. These tools are sufficient to compute the expected reliability differences of overhead versus underground in non-storm conditions. However, these tools are not appropriate to assess reliability under severe storm conditions. There are almost no publications that address storm reliability modeling of electric distribution system. One suggests the use of a non-storm algorithm with different failure rate and repair times. This approach is not suitable for hurricane simulations. One paper presents a simulation methodology to compute expected performance during major wind storms. This includes the prediction of storm severity, restoration efforts during the storm, and post-storm restoration. Data used in this paper is not based on hurricanes, but the basic approach could be used as a basis for a hurricane simulation.
2.5 Failure Rate Modeling
Accurate prediction of system reliability requires accurate estimates of equipment failure rates. For example, non-storm benefits of undergrounding require information on overhead line and underground cable failure rates. There is a host of data on average equipment failure rates in a variety of publications, most of which are summarize. These are sufficient to do a basic examination of non-storm reliability, but utility-specific data often varies substantially from industry averages. Other papers discuss the relationship of equipment condition to failure rate.
The literature is consistent in its recognition that undergrounding is expensive relative to the embedded cost of existing overhead systems. However, it is often not emphasized that there are three initial costs related to undergrounding. The cost most commonly considered is the cost for a utility to remove the existing overhead electrical facilities in easements and rights-of-way and install equivalent underground facilities. The second is the cost of converting or modifying each individual customer’s “private” service equipment (service drops and entrance, meter box, etc.) to accommodate new underground electric service. This second cost can be substantial and is almost always born directly by the associated customer. The third cost is for undergrounding other utilities such as telephone, cable television, and broadband fiber. There is an offset for this third cost since the third-party utilities will no longer have to pay an attachment fee to the electric utility. Virtually all undergrounding projects place all over head utilities underground. However, many undergrounding studies do not consider the cost of undergrounding third-party attachments.
Ultimately, the cost of any undergrounding project has to be paid. Selecting the most appropriate financing option and setting the cost allocation policy (who pays what portion of the cost) is a critical part of the overall undergrounding process. Most commonly, funding for initial constructing comes from one or more of the following: increased taxes, increased electricity rates, and direct contributions from customer. Funding must also be considered for other undergrounded utilities such as telephone, cable television, and broadband fiber. Most commonly, undergrounding plans involve a specific group of customers such as a municipality or a “special assessment district.” In addition, most studies recognize that individual customers must absorb the cost of converting their own service facilities to take underground service. This can be a financial burden to the individual customer with implication of its own.
The literature most commonly attributes to underground distribution systems the following improvements as compared to overhead transmission systems.
1. More reliable electric service with fewer failures
2. More economical to maintain and service
4. Positive value to nearby property and
5. More desirable during adverse weather.