Review and Recommendations Concerning Natural Gas Distribution Tariff
Methodologies in Colombia
1. Background
CREG Resolution 057 of 1996, Articles 70 through 129 outline the broad parameters
within which natural gas distribution and related activities are regulated in Colombia.
General tariff formulas are included in Articles 107 and 108 in particular. These tariff
formulas apply to and are calculated for a five year period. CREG Resolution 007 of
2000 provides an alternative tariff structure that can be adopted at the option of the
distribution company.
The natural gas distribution industry in Colombia exhibits a variety of market and
industry structures. In some municipalities, natural gas distribution is subject to
exclusive rights which have been awarded as a result of competitive bidding. In others,
natural gas distribution is subject to potential competition. Various levels of market
penetration and market maturity can also be observed. In all cases, the regulatory
objectives are to create an open, competitive, and economically efficient market for
natural gas.
Natural gas distribution tariffs must meet the following standards:
 They must precisely describe the services offered and their quality;
 They must describe the expected level of market coverage;
 They must state the expected charge per unit of consumption;
 They must identify any fixed charge to cover the costs of guaranteed availability of
network services;
 The must define connection charges and the method of amortization of connection
charges;
 They must identify the distribution costs for each stratum;
 They must define any maximum or minimum charges; and
 They must identify the period for which the tariff applies.
As part of its ongoing process of reviewing natural gas distribution tariffs, the CREG
contracted with Consultores Economica (the Consultant) to perform a review of current
and alternative tariff formulas. This review included key parameters of the existing
formula, its overall effectiveness, and alternative methodologies. The Consultant
considered various forms of average revenue caps, price caps, tariff basket formulas, nonlinear pricing (primarily the mandatory option), and efficiency prices. Traditional cost of
service regulation was not considered as an option, but was used as a standard of
comparison in certain elements of the review.
The Consultant provided theoretical and analytical reviews of the key regulatory options
examined, as well as empirical modeling results. On the basis of this analysis, the
Consultant recommends significant change in natural gas distribution tariff
methodologies for the future. The recommended approach is one of a mandatory option
pricing structure with efficiency prices as the default tariff. As a second choice, the
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Consultant suggests a weighted tariff basket approach with efficiency prices as the
average price cap.
2. Scope of CERI Review
The Canadian Energy Research Institute (CERI) provides this report at the request of the
CREG. This review considers a number of issues relative to the Consultant's report. Any
tariff formula must be based on principles of fairness and must allocate costs to the
customers that cause them to be incurred. It must also consider the balance between
managing precise costs of providing service and the need to minimize reliance on
forecasts or true-up mechanisms. When a change in the tariff formula is contemplated,
the potential financial impact on the distributor, its shareholders, and its customers must
be considered. Further, the distribution tariff methodology must be consistent with the
broader context of natural gas regulation, and must contribute toward the policy
initiatives defined by the Ministry of Mines and Energy (MME).
CERI has reviewed overall natural gas regulations, as well as those specific to natural gas
distribution. Based on regulatory principles, current regulations, current industry
structure, and experience in other jurisdictions, CERI provides the comments and
recommendations contained in this report. CERI has also undertaken consultations with
the CREG, the Consultant, the MME, and a number of natural gas distributors.
3. Issues
3.1 Key Issues identified by Consultants
The Consultant's review identified several key issues as part of its analysis:
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Maintaining a link between the cost of providing service for each customer class and
the tariffs that apply to that customer class. Cross-subsidization in existing tariffs
allow residentials and industrials to pay the same price;
The single city-gate gas price creates difficulties in industrial market capture;
Providing appropriate efficiency incentives without impairing the ability of the
distributor to recover investment;
Fixed/variable cost allocation and two-part vs. one-part rates;
Whether or not to incorporate an efficiency adjustment (the X factor) in the tariff
formula and how to choose the factor;
Significant tariff differences between exclusive and non-exclusive zones raise
questions about efficiency incentives vs. market characteristics;
The separation of network charges from all other costs of distribution system;
Conversion costs provide a potential constraint to market capture;
Subsidies for competing fuels, particularly in lower strata may provide a significant
barrier to natural gas market penetration;
The regulatory capacity to implement whatever option is chosen; and
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The quality of available data and the need to do further modeling at a company level,
with appropriate consultation. There is also a sub-issue of information bias;
The first two issues address a key regulatory principle that any tariff mechanism would
be designed to achieve. The level of cross-subsidization in any tariff system must be
carefully monitored to ensure that it supports other regulatory objectives. In the current
case, it appears that charging the same tariff to all users creates a potentially strong crosssubsidy from regulated industrial to residential customers. This cross-subsidy may be
acting as a disincentive to further penetration of the industrial market for some
distributors. Charges for both network services and natural gas supply (at the city-gate)
should be based on the principle that the customers who cause the costs should be
responsible for their recovery. Deviations from this principle create cross-subsidies
which may have unintended consequences for market penetration, and may create bypass
incentives.
The next three issues deal with the question of economic efficiency. Distributors must be
permitted a reasonable opportunity to recover their investment, together with a return to
shareholders. However, they must be provided clear incentives to invest efficiently, and
to operate efficiently, thereby minimizing the resources required. The choice of a tariff
methodology can strongly influence these incentives. The formula chosen, and where
appropriate, the efficiency factor applied to tariff increases, will provide investment
incentives for the utility. For certain methodologies such as cost of service regulation,
there is valid concern that these incentives are not clear. The question of rate design,
particularly the split between fixed and variable charges can also send strong efficiency
signals to end customers.
There is also the possibility that different markets with different structures and levels of
maturity may respond differently to a given tariff formula. The Consultants identify
significant differences between exclusive and non-exclusive distribution zones in
Colombia, raising the question of efficiency incentives and market structures between the
zones.
The issue of unbundling is raised only briefly in the context of separation of network
charges from marketing and gas supply charges. This issue normally arises in the context
of clear and efficient price signals. In theory, when end customers can clearly see the
costs they must pay for access to the network vs. the natural gas, they will have a greater
tendency to manage and optimize those costs separately. There will also be greater
potential for competition, particularly in natural gas supply and marketing activities. In
Colombia's context, unbundling of network and gas costs arises in another context. Much
of the current difficulty with the existing tariff methodology arises because of the
volatility of natural gas prices and transport services that are priced in US dollars, but
billed in pesos. This creates the need for an adjustment mechanism as discussed below.
Conversion costs and competing fuel subsidies are two key issues relating to the gas
massification program. To the extent that the treatment of conversion costs, or subsidies
embodied in competing fuels prices inhibit natural gas market penetration, the objective
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of growing the natural gas market is frustrated, and existing customers may pay higher
distribution costs than necessary.
Finally, the Consultant identified certain issues related to implementation. The CREG
and the industry do not have a regulatory tradition that includes cost of service regulation.
They have instead opted for simpler mechanisms that are designed to provide less market
intervention, but still maintain clear efficiency incentives and flexibility. The
Consultants consider regulatory alternatives that are intended to be consistent with these
objectives. At the same time, they are proposing methodologies that require additional
information and analysis relative to the existing formula, and recognize the implications
for the CREG and the industry.
3.2 Additional Issues Identified by CERI Consultations and Review
The review and consultations undertaken by CERI have identified additional issues
relevant to the distribution tariff methodology to be employed by the CREG:
 Separation of industrial and residential markets for tariff purposes;
 Impediments exist to further market capture by the distributor. Some are tariff
related, others are related to cost recovery mechanisms that are very short term;
 Information requirements of the efficiency pricing methodology;
 The efficiency price approach has not been implemented in other jurisdictions. This
could impose additional costs of pioneering on Colombia's natural gas market;
 The Consultants used a limited information base;
 The choice of a number of market parameters is critical to model results;
 A number of costs have been specifically excluded from the model.
 The methodology abstracts from key issues such as asset valuation because it does
not deal with the actual costs of any given enterprise. This will need to be considered
as further work is completed at a more detailed level.
 Passthrough mechanisms currently create significant price volatility to end customers.
 The trade-offs between simplicity, information requirements, price signals, and
efficiency incentives is clearly at play. All parties believe in market price signals and
efficiency incentives, but have differing views on how much information should be
collected, and on how complex the tariff formulas should be.
Several of these issues apply to the existing tariff formula. The current adjustment
formula which is based only on residential deliveries is creating a market distortion and
providing distributors with a disincentive to discount the cost of their services to attract
new industrial customers. It also acts as an impediment to industrial gas consumption in
markets where effective competition from alternative fuels exists.
Others of the issues relate to the methodologies proposed by the Consultant. Costs that
have been excluded from the analysis might include some of the non-network assets of
the companies such as buildings, communications equipment, vehicles, etc. These costs
could have a substantial impact on the tariff calculations. Also, the treatment of specific
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items such as working capital has not been clearly identified in the report. If costs have
not been included, the issue of interpreting resulting tariffs must be addressed.
Key parameters include the discount rate, the method of asset valuation, and the rate of
growth in future consumption for each sector modeled. The choice of these parameters
will require significant interaction between the CREG, the distributors, and other
stakeholders.
Also, because the information requirements between COS and efficiency pricing are very
similar, the regulatory capacity required for efficiency pricing may be quite similar to
COS methodology. This is an issue to be explored prior to implementation of efficiency
prices.
A mechanism to provide greater price certainty to distribution customers is also desirable.
Exchange rate volatility and the accompanying risk is a key source of uncertainty in the
market. Mechanisms are developing to manage the risk, but this is a significant policy
issue. Oil price volatility presents similar difficulties. Secondary market purchases of
available short term gas (primarily from thermal electrics) creates additional potential for
price volatility.
4. Review of Consultant's Methodology
This section comments briefly on the methodology adopted by the Consultant. This
methodology includes both the process they adopted for information gathering, as well as
their theoretical approach and the tariff formulas considered. As a general comment,
CERI believes that the Consultant's findings are well grounded in both economic and
regulatory theory.
Information gathering and company consultations
In order to prepare empirical models of the tariff options considered, the Consultant was
required to gather information and data with regard to each distributor considered. The
Consultants was provided with limited information upon which to base analysis. In some
cases the information may not have been available, in other cases it may not have been
requested. Given that the report contains comparisons across methodologies, including
the tariff impacts, additional work will need to be done.
The Naturgas members consulted expressed their willingness to participate in an open
process of information sharing leading to a more complete analysis of the options being
recommended. This process would receive better support if a timetable is established,
and clear objectives and expectations are identified at the outset. The Consultants
indicated that they are aware of the data limitations of their analysis. They adopted ruleof-thumb or statistical approaches because of the limited information available to them.
They recommended further work be done on company-specific modeling.
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The distributors were not invited to comment on the cost assumptions made by the
Consultant. They were not provided any detail with regard to the model results for their
companies. The Consultants also expressed concern over the information bias that exists
in favor of the distributors.
No benchmarking analysis was included in the information gathering phase. This type of
analysis could have provided a cross-check against information provided from other
sources.
On balance, the Consultant has done a credible job of preparing analysis based on
available information. Once a tariff formula has been chosen, further consultation will be
an important step in ensuring that the interest of all parties have been respected.
Tariff methodologies considered by the Consultants
The Consultant examined four primary options for distribution tariffs: average revenue
regulation, tariff basket, non-linear pricing (mandatory option), and efficiency prices.
Each formula is reviewed in detail, and modeled in the specific context of gas distribution
in Colombia. The review is careful and thorough. In addition, cost of service
methodology provides an implicit standard for comparison, particularly in areas such as
information requirements and regulatory oversight required.
5. Review of Tariffs
5.1 Current Tariffs
The CREG currently offers two tariff mechanisms to natural gas distributors. The first
option is a combined average revenue cap and price cap and was established pursuant to
CREG Resolution 057 in 1996. Under this system, each distributor must certify that, on
an annual basis, the distribution tariff does not exceed a value set by the CREG. The
maximum tariff is set for a five year period, with appropriate annual escalation. The
distribution tariff is the sum of natural gas acquisition cost, natural gas transport cost,
distribution network charges, marketing charges, and an adjustment factor. The
maximum tariff is measured in pesos per cubic meter of gas delivered. Each distributor is
permitted to set a fixed and variable tariff, as long as the average revenue does not exceed
the maximum tariff.
The adjustment factor in this tariff formula has been the source of significant difficulties.
The adjustment is used to true-up actual revenue from the previous period to the average
revenue cap. This true-up, however, is based solely on residential consumption, and
therefore acts as a disincentive for distributors to offer discounts to industrial consumers.
The adjustment factor has also been problematic in that it includes natural gas costs and
transport costs. Wellhead natural gas costs as well as transport costs are determined in
US dollars, but are charged to the end customer in pesos, introducing an element of
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volatility due to exchange rate fluctuations. Natural gas costs are also indexed to
NYMEX crude oil prices, introducing an element of commodity price variability into the
adjustment factor.
The second tariff alternative available in Colombia was established by CREG Resolution
007 of 2000. This tariff option has not been widely adopted by the industry to date, but is
intended to remove the complications of an adjustment factor in the formula. This option
is only available under conditions of free competition, and must be elected by the
distributor. Once chosen, this option becomes the tariff from that point on.
The tariff option is calculated on a monthly, rather than annual basis. It includes the
average cost of gas acquisition, transportation, distribution, and marketing. The tariff is
further disaggregated between regulated residential and regulated non-residential natural
gas consumers. For each customer class, the distributor is permitted to choose the
allocation of costs between fixed and variable charge, as long as the average revenue
does not exceed the regulated maximum.
5.2 Proposed Tariffs
From among the set of possibilities examined, the Consultant identified two primary
options as having potential for implementation in Colombia. These options were a tariff
basket approach, and a mandatory option. This section of the report briefly summarizes
the two methodologies, their strengths and weaknesses as identified by the Consultant,
and provides additional commentary with regard to the methodologies and potential
transition issues should either methodology be adopted. Efficiency pricing is integral to
the mandatory option tariff as proposed, and is also recommended for consideration as
the price cap in the weighted tariff basket formula. However, efficiency pricing is
considered as an independent item, simply because either tariff option could be
implemented without efficiency pricing if a suitable method of defining the default rate
or price cap rate were established. The most obvious candidate for these roles would be
the existing average revenue cap, appropriately adjusted to apply to the sector being
considered.
5.2.1 Weighted Tariff Basket
The weighted tariff basket methodology places a cap on the weighted average price
across all users. The utility is free to set prices for each customer class such that the
weighted average price is at or below the cap set by the regulator. The weights used in
determining the average price are the actual volumes of gas consumed by each customer
class in the preceding period.
The weighted tariff permits the utility complete freedom in determining the split of fixed
and variable charges for each customer class. The price for each customer class that is
used in the tariff basket calculation would be the sum of the variable charge and the
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average fixed charge applied to that customer class. The average fixed charge would be
based on the previous year's consumption.
The tariff basket approach allows the distributor flexibility in setting prices for each
customer class, but does not permit price discrimination between customers within a
customer class.
The Consultant concludes that the tariff basket provides an incentive for market
penetration in that the distributor will raise prices in inelastic markets, and lower prices in
elastic markets. Because of relative price elasticities, the volume increase in the elastic
market may be greater than the volume reduction in the inelastic market. From year to
year, the weight accorded the elastic market will increase as a result of relative elasticities
and price adjustments, permitting greater flexibility to raise prices in the inelastic market
without violating the weighted average price cap.
This potential for price discrimination between sectors is a key element of the weighted
tariff basket approach. If distributors behave in the manner described, the end result will
be distribution tariffs that are based on the value of service to each class of customers,
rather than the cost of that service. This is a fundamental issue that has important
implications for the economic efficiency of the tariff, as well as for wealth distribution
across customer classes. In other words, it has the potential to result in residential
customers subsidizing industrial customers, an undesirable situation in any jurisdiction.
Using this tariff methodology, customers that rely on the distributor for network service
as well as gas supply would be subject to a common weighted average price cap.
Customers that rely on the distributor for network services only, would be subject to a
separate price cap. For these customers, the distributor would have complete freedom
with regard to the split between fixed and variable charges, and would be permitted to
discount. No network service customer would pay above the price cap. For customers
that are connected directly to the national grid, a marketing charge would apply in a
similar fashion.
The Consultant proposes that the price cap be based on either the existing distribution
tariff for each company, or the efficiency price calculated for each customer class
separately.
The weighted tariff basket approach requires that the market be segmented appropriately
between the three major customer groups, and within the group of regulated customers,
between appropriately defined customer classes. In order to calculate efficiency prices,
the Commission will require both consumption volumes and costs allocated to each group
and class of customers. The Commission will also require that the distributor submit the
actual tariff charged (including fixed and variable charges), and the consumption level for
each group and class of customers. This information will allow the CREG to verify that
the weighted average price cap has not been exceeded. Further, for all customers that
arrange their own gas supply, the CREG will need to audit billing information to ensure
that no customer has been charged more than the CRt price cap that applies to that group.
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Similar audits may be required for by-pass customers. A regulation to implement the
weighted tariff basket methodology would need to clearly specify the information to be
supplied, the information that must be available for audit, the potential penalty for not
providing required information, and the potential penalty for not complying with the
price caps.
The Consultant considers the advantages of this tariff to be its incentive for aggressive
market penetration, its ease of implementation, and its reliance on historical data, thereby
avoiding any need for adjustment mechanisms. The disadvantages are the potential for
price increases in the residential sector, the risk of strategic behavior that results in loss of
residential customers, and increase information requirements to permit the regulator to
define market segments.
CERI believes that the Consultant has understated the level of effort that will be required
on an ongoing basis to oversee this methodology. Customer-specific information and
compliance auditing will be required for all non-regulated and bypass customers. Annual
review of billing information will also be required to verify volumes allocated to each
customer class, and to verify that charges have not exceeded the price cap.
More importantly, CERI believes that this formula gives the distributor the option of
basing its charges to the residential sector on the value of service, rather than its costs.
The distributor will have the option of increasing prices in the inelastic residential
market, perhaps even generating revenues significantly higher than the costs of serving
that market. Such behavior would violate one of the key tariff objectives identified by
the Consultant (rates that reflect the cost of providing service). This alone is sufficient
grounds to reject the weighted tariff basket approach, given Colombia's economic
situation and the stated massification policy.
In addition, CERI believes that one of the potential advantages of the tariff basket
approach has been significantly over-stated. Although it is true that no adjustment
mechanism would be required, it is also true that the adjustment mechanisms in the
current tariff formula are more related to the variations in the wellhead price of natural
gas and in exchange rates, and are not related to variations in distribution network costs.
The tariff basket formula described by the Consultant would apply to the network charges
only. Exchange rate and gas price fluctuations would still exist, and would still require
adjustment mechanisms of some sort.
5.2.2 Mandatory Option
The mandatory option pricing methodology provides significant flexibility in an attempt
to encourage economically efficient pricing of a utility service. Under this pricing
method, the utility company will define a different price menu for each of a series of
customer classes. Each customer class represents a range of potential consumption, with
each customer being assigned to a customer class on the basis of historical consumption.
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In this manner, discrimination between customers with similar consumption levels is not
possible.
For each customer class, a tariff menu must then be defined. The tariff menu would
consist of a series of two-part tariffs. Each tariff would have a fixed monthly charge and
a variable charge based on the volume of natural gas consumed. The levels of fixed and
variable charges would vary across the menu for the customer class. The fixed charge
would be lowest for the lowest level of consumption, and would rise as consumption
increases. The variable charge would decrease as consumption increases. Each customer
would be offered the menu consistent with its level of consumption.
Under the mandatory option, the utility would be required to offer a one part rate ($/m3)
to all customers as an additional option. The level of this mandatory option tariff would
be set by the regulator. The Consultant's analysis bases the mandatory option tariff on
the efficiency price.
The mandatory option would have at least two sets of menus for full service customers,
one for residential customers and another for industrials and other large consumers. In
addition, menus would be required for industrial customers that rely on the distributor for
network service only (arranging their own gas supply), and for clients served by the
distributor, but connected directly to the national transportation system. For network
service customers, the tariff would act as a price cap, with the fixed/variable split subject
to negotiation between the parties. This rate would be based on network costs only. For
customers connected to the national transport system, a marketing charge based on
commercialization costs alone would act as the mandatory option.
With a mandatory option tariff, the regulator must review and approve the mandatory
option price for each category of users. In order to do this, the regulator must have
sufficient cost detail to allocate the distributor's costs between broad customer classes.
The investment costs, and AOM costs that are incurred to serve residential customers
must be separated from those related to industrial customers. This is necessary in order
to determine the efficiency price that applies to residential vs. industrial customers.
The regulator must also have knowledge of the split between fixed and variable costs.
This is necessary in order to ensure that the fixed/variable splits chosen by the distributor
are within a reasonable range. Finally, commercialization or marketing costs must also
be separated from other costs in order to define the mandatory option tariff for users
connected to the transmission grid.
Once the regulator has determined what the mandatory option rate will be for each
customer class, and has determined that the fixed/variable menus offered by the
distributor are appropriate, mandatory option rates for the first year of the regulatory
period can be set. The regulator must then set a rate of escalation for the mandatory
option rates. The Consultant argues that this rate should be set at the rate of consumer
inflation in Colombia. The Consultant does not believe that any efficiency adjustment
should be imposed on the tariff escalator. In the case that the mandatory option rate is
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simply the efficiency price, care must be taken to ensure that the inflation rate applied is
consistent with the assumptions used to generate the efficiency price. If not, the
mandatory option rate may not generate an economically efficient result.
The Consultants identify numerous advantages to the mandatory option tariff
methodology. They conclude that it will protect small customers because the mandatory
option rate will be based on economically efficient pricing. This option is expected to
provide market penetration incentives to the distributor because the distributor is
expected to reduce variable charges for industrial customers to marginal cost. Further,
the tariff would be directly linked to actual costs of providing service to each market,
without moving to full cost-of-service information requirements, and without permitting
price discrimination between users with similar volume requirements. The mandatory
option allows the utility to capture fixed costs through fixed charges and variable costs
through variable charges, providing efficient price signals with regard to network
expansions. The approach is also considered to require minimal oversight, since the
regulator can focus on setting the initial rate, then auditing the distributors to ensure
compliance with the identified menus.
Disadvantages of the mandatory option are considered to be fewer in number. Because
this methodology was developed for price sensitive communications markets, there is
some uncertainty regarding how customers will respond in residential natural gas markets
which are inelastic in nature. Because natural gas provides essential services, it is not
clear whether existing residential customers will be able to respond to the price signals
generated. In addition, the Consultant expressed concern that distributors might not have
the ability to penetrate industrial markets, even with the mandatory option flexibility, and
might choose to focus their efforts on residential markets. Finally, the Consultant
recognizes that this is a complex pricing structure. The utility must consider both
demand characteristics and the behavior of the costs of providing services. This may act
as a barrier to setting tariff structures that maximize economic welfare.
5.2.3 Efficiency Pricing Methodology
The efficiency pricing methodology is based on the concept of estimating costs that
would be incurred by an efficient service provider, and then building a tariff that
embodies those costs. In this sense, it is intended to address two of the fundamental
weaknesses of the more traditional cost of service (COS) methodology. COS requires the
regulator to scrutinize actual costs of each distributor at a careful level of detail, and to
determine whether those costs can be included in tariffs. In addition, the COS
methodology has been criticized because it creates incentives for the distributor to grow
its income by growing its cost base, rather than provide service at the lowest, most
efficient cost possible.
The Consultant begins from the premise that COS regulation is not a practical alternative
for an immature market such as Colombia because of its lack of efficiency incentives,
and because of the regulatory capacity it requires. CERI agrees with this assessment.
The Consultant then examines efficiency pricing as a means of aligning tariffs with the
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cost of efficiently providing service to each customer class, and concludes that this can be
done with minimal information requirements. It is important to note that efficiency
pricing can only achieve this objective if the model structure, parameters, and input
assumptions accurately represent an efficient distribution system. Given the diversity of
market sizes, types, and maturities in Colombia, accurately capturing efficient behavior is
a difficult task. Further, the methodology is based on long term projections (25 years) of
market growth and financial conditions. It is unlikely that these projections will be
accurate, introducing the probability that the efficiency prices will not accurately reflect
the actual evolution of market conditions.
The efficiency pricing model requires historical data regarding the distribution company,
a series of engineering-economics rules of thumb to determine efficient network costs,
and a set of financial and market related assumptions. The historical data are used to
define the customer base, rate of growth, network size, and gas costs of each distributor.
Rules of thumb are used to define the efficient network based on geographic extent, size
and type of lines required per customer, industrial market potential, AOM costs, etc.
Financial and market growth assumptions are then used to project network costs and
revenues into the future. The discount rate applied to revenues and sales volumes is a
key parameter. Based on these data, and 25 year forecasts for relevant variables, the
efficiency price model solves for a net present value of revenues less costs that is equal to
zero. Alternatively, this can be viewed as solving for a price path that gives an internal
rate of return exactly equal to the discount rate chosen as a model input.
The efficiency pricing model also permits separation of costs and estimation of tariffs for
each customer class, as well as separation of costs between network, AOM, and
marketing functions.
The Consultant presents calculated efficiency tariffs at a company level and compares
those tariffs to current distribution charges. These results are qualified by statements that
they are based on the inputs and assumptions used, which are in need of potential
modification by the CREG after a process of consultation with the industry. They are not
put forward as a tariff recommendation.
CERI agrees with the Consultant's view, and notes that the distributors raised the same
point. The model results to date should be viewed cautiously. The variations across
companies may be more reflective of the fit or lack of fit of model parameters and data to
the particular circumstances of each company, rather than predictive of appropriate
tariffs. In addition, the Consultant has not captured the entire cost base of each
distributor. The distributors note that certain non-network assets such as buildings and
vehicles may not have been included in the analysis, making any comparison between
calculated efficiency prices and actual tariffs difficult to interpret. Further, the
distributors take issue with the manner in which the discount rate has been determined.
This is a key parameter in the analysis. The rate of market growth and the rate of market
penetration are also key assumptions that need to be reviewed with the distributors prior
to finalizing the model results.
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After the CREG and the companies have completed consultations on the parameters and
assumptions to be used, the calculated tariffs and comparisons to actual tariffs will take
on greater significance. At that stage, the Commission will wish to review the impact on
rates for each distributor and customer class that would result from moving to efficiency
prices. The CREG may also wish to investigate the impact that such changes could
potentially have on company financial results.
Because of the potential rate shock identified by the model results for certain companies
and certain end use sectors, the Consultant proposes that if efficiency prices are adopted,
a phase-in period will be required to prevent undue burdens on end customers. CERI
agrees with this observation if the final efficiency price calculations indicate similar
results. CERI also notes the significant cost variations in the results between residential
and industrial markets. Industrial tariffs would be very small relative to residential tariffs
under the efficiency cost methodology. This suggests that a careful review of the
allocation of network facilities between these two sectors is warranted, should efficiency
prices be adopted. These allocations also provide an explicit means of measuring crosssubsidization between customer classes. The Commission may wish to initiate further
investigations into the relationship between the level of cross-subsidization and resulting
market penetration under efficiency prices.
Sensitivity cases prepared by the Consultant indicate that the calculated tariffs are
sensitive to the base year consumption that is chosen, and to the treatment accorded to
industrial customers connected directly to the national transmission grid.
5.3 Review of Consultant Recommendations
5.3.1 General Issues
The Consultant identifies five primary objectives to be accomplished by the proposed
regulatory formula:
 Promote gas massification and market penetration,
 Match tariffs to the cost of providing service to each market,
 Avoid price discrimination between users with similar consumption characteristics,
 Design formulas that are simple, appropriate, and easy to administer, and
 Avoid including estimates or projections in the application of the formulas.
Because the majority of the costs facing natural gas distributors for the purposes of
establishing tariffs are exogenous, fixed in nature, and easily observable, distribution
tariffs should be based on the efficiency pricing methodology. This could result in a
CREG resolution that would base tariffs on the efficiency pricing methodology, using
specific data agreed upon by the Commission and the distributors. This would provide an
efficient, transparent pricing methodology.
5.3.2 Incorporating City Gate Gas Costs in the Regulatory Formula
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The Consultant recommends that the city gate price of natural gas for regulated markets
be determined as the distributor's average monthly gas purchase costs plus average
transport costs. Both costs would be measured in US dollars per cubic meter, then
converted to pesos using the official exchange rate of the Superintendencia Bancaria as
stated for the last day of the month. This city gate gas price would be shown separately
on all end customer service bills. This treatment would be consistent with CREG
resolution 007. The consultant further recommends that the city gate gas price be based
on actual prices and consumption, rather than forecast values. This would require a one
month billing lag, but the related costs are judged to be of lesser importance than the
difficulties that arise when the city gate gas price is based on projections or estimates.
The Consultant recognizes that this formula imposes the full risk of exchange rate
variations on the end consumer of natural gas. This results in price volatility for the end
customer, which could, if desired, be reduced by using a moving average.
CERI's view is that this is one of the fundamental issues facing Colombia's natural gas
industry at all levels of the value chain. CERI concurs fully that the city gate cost of
natural gas be show as a separate item on each end customer bill. This minimal level of
unbundling of charges is essential to clear market price signals. It also permits the end
customer a clear view of the source of any volatility in energy costs.
A potentially more significant issue is the allocation of exchange rate risk between
market participants. Given that natural gas and transportation are both priced in US
currency, a policy decision has been taken to insulate natural gas producers and natural
gas transporters from exchange rate risk. In regulated markets, the risk must therefore be
borne by the distributor or the end customer. As indicated above, the proposed formula
imposes the full risk on the end customer. In CERI's view, there is an additional
flexibility that might be accorded to the market. In the particular case of residential
customers, the natural gas consumer is unlikely to have any means of mitigating or
managing this risk. The distribution utility, on the other hand, may have the financial
resources and the desire to manage or average this risk. The regulator should be open to
this possibility.
In particular, the distributor may wish to offer the regulated market the option of
purchasing gas priced in dollars or pesos. The peso price might be based on an average
of historical exchange rates, on expectations of future performance, or on some
established hedging program. The distributor would then have an expectation of being
rewarded for accepting this risk and reducing the resulting price volatility. The regulator
would need to approve the exchange rate applied, and ensure that the distributor earned
an appropriate return for the service offered.
5.3.3 Distribution and marketing tariffs
The Consultant recommends that existing tariff methodologies be allowed to lapse, and
that they be replaced with the mandatory option methodology, using efficiency prices as
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14
the mandatory option. A second choice would be the weighted tariff basket (with lagged
consumption as the weights), using efficiency prices as the average price cap.
CERI agrees that either of the Consultant's recommendations could be accepted by the
CREG. Concern arises, however, because efficiency pricing has not previously been
implemented in the natural gas distribution industry. This creates an element of
regulatory uncertainty that may not be necessary. Further, prior to implementing
efficiency pricing, the CREG must undertake further analysis and consultation with
industry.
Three significant issues arise with respect to efficiency pricing. The first is its reliance on
rules of thumb to estimate the costs that will be used as a proxy for an efficient
distribution system. Second is its use of long term forecasts. Third is the information
burden it may place on the CREG as well as the distribution companies.
The reliance on rules of thumb and engineering estimates on calculating efficiency prices
is an important issue of economic efficiency. The underlying principle is to break the
incentive for the distributor to attempt to grow the rate base by incurring costs above the
efficient level. Although this is an important theoretical objective, if the basis for
estimating efficient costs is inaccurate, the distributor will be unduly rewarded or
punished, depending on the nature of the inaccuracies. Given that the efficiency cost
study was based on publicly available information, and limited communication with the
distribution companies, these types of inaccuracies are likely to exist, and will need to be
investigated before efficiency prices could be properly implemented. This may require
extensive benchmarking both within Colombia, and to other nations. Mexico may
provide a number of relevant examples from its recent experience with competitive
bidding for new distribution franchises. Further, the CREG must recognize that
particular flexibility will be required in the case of immature markets. An efficient
design in such markets may need to include significant allowances for future market
growth.
The efficiency pricing methodology relies heavily on forecasts of future market
penetration, population growth, inflation, and financial conditions. The Consultants point
out that the model is particularly sensitive to future market growth. The distributors
correctly point out that their shareholder earnings are directly sensitive to the discount
rate chosen. To the extent that key parameters are accurately forecast, efficiency prices
could encourage economically efficient price signals and optimal behavior. Forecast
errors are likely to have negative implications for some market participants, and to
generate economic rent for others. This element of forecast risk does not exist in the
current formulas, and represents a key disadvantage of the efficiency pricing
methodology.
Finally, the issue of information requirements must be addressed. Efficiency pricing has
the advantage of abstracting from the historical investments made by any given
distribution company, opting instead for a generic representation of an 'efficient' level of
investment. However, in order to validate the physical parameters of the model, the
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Consultant has appropriately relied on information from the historical investments made
by the utilities. The distributors have already pointed out that the model must be
calibrated and capable of representing a wide range of market and physical conditions
that currently exists in Colombia. CERI agrees that further work must be done on this
issue prior to implementing efficiency pricing. This process of information gathering
will take the parties in a direction very similar to the cost generation and allocation
studies that are typical of cost of service regulation.
In addition to the historical information required, efficiency pricing will require a number
of long term projections of key variables. These projections are subject to evaluation in a
highly uncertain context. A key example is the discount rate chosen by the Consultant
and questioned by the distribution companies. The Consultant used a CAPM/WACC
approach, accompanied by a capital structure they chose to be representative. The
distributors wish to put forward their alternative view on all of the details before agreeing
to the use of any particular discount rate. Fairness to the distributors' shareholders
suggests that some type of CREG-sponsored review process be followed. Again, this
leads down a very similar path to the cost of capital and return on capital investigations
typical of cost of service regulation. The additional complexity is efficiency pricing
requires that key parameters be forecast over a much longer future period than is typical
of the cost of service methodology.
For these reasons, CERI would advise the CREG to adopt a gradual approach to
efficiency pricing, accepting the Consultant's recommendation only after careful
assessment of the regulatory burden. A strong commitment to oversight of this option
will be key to its success.
5.3.4 Connection Charges
The Consultant considers that the current method of dealing with connection charges is
adequate, and makes no recommendation for change in this area. The potential for
accelerating market penetration by offering methods of financing connection charges is
judged to be beyond the current capacity for oversight.
CERI disagrees strongly with this recommendation. Consultations with industry
representatives indicate that, in their view, connection charges represent a significant
impediment to market penetration. Residential customers might be required to pay a
conversion cost that is larger than their current annual bill for a competing fuel. In these
cases, connection is not likely to occur. Further, the customer is directly responsible for
payment of the connection cost over a period as short as three years. This treatment of
connection cost erodes the potential benefit of natural gas to the end customer.
Two approaches might be considered to deal with connection charges. The first would be
to allow the distribution company to include the costs up to and including the meter
installation in its invested capital. The cost would then be recovered from all residential
customers through future distribution charges. This method has three advantages. It
provides the distribution company with the ability to grow its investment by connecting
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new customers, creating and additional incentive to market to residences. The second
advantage is that it more accurately matches the term over which costs are amortized to
the useful life of the connection facilities. Finally, the connection cost would be spread
over a long enough time period that it would not present a barrier to the residential
customer. The one disadvantage of this change is that existing customers have already
paid those connection costs directly, and would be required to share in the costs of
connections that occur in future. The extent of this cross-subsidy and the impact on rates
could be estimated for each distribution company if desired. On an annual basis, each
company would be required to prepare a report for the CREG detailing new connections,
related investment, and the calculated impact of this investment on the unit cost of
serving residences as well as any potential tariff impact.
For new industrial connections, the same approach could be adopted. Alternatively, each
industrial connection could be amortized separately. The amortization period could be
chosen so that the total delivered cost of natural gas (including the amortization of
connection facilities) remains competitive with the alternative fuel. If this is considered
too complicated, the amortization period could be arbitrarily set based on the average
expected payback of such facilities.
5.3.5 Subsidies
The Consultant recommends that the city gate price of natural gas not be subsidized,
according to a non-legal interpretation of Article 99.6 of Law 142. Subsidies would be
limited to costs related to network investments only. Under the mandatory option tariff,
the subsidy would be based on a subsistence consumption level of 20 cubic meters. For
the price basket tariff, the subsidy could be based on the network charge and subsistence
consumption for the group receiving the subsidy.
Given that natural gas distribution network charges are a small portion of the delivered
cost of natural gas to residential users, the level of the subsidy is likely to be quite small.
The relationship between subsidies on natural gas and subsidies on competing fuels might
therefore be a significant impediment to natural gas penetration in some markets. This is
an issue for joint assessment between the CREG and the policy arm of the Ministry of
Mines and Energy.
5.3.6 Regulatory Oversight of Proposed Methodologies
Mandatory Option
The Consultant identifies the following regulatory oversight requirements in order to
implement the mandatory option:
 Establish mandatory option price levels, marketing charges, and pricing for network
use charges. Review every five years;
 Ensure that the mandatory option is offered to all users;
 Ensure that the full slate of menus is offered;
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


Ensure that each menu has fixed costs that rise with consumption and variable costs
that decline with consumption;
Ensure that the above menus are available to network customers and bypass
customers; and
Determine annually the appropriate indexation of all charges in all menus.
Tariff Basket
The Consultant suggests that regulatory oversight of the Tariff Basket would be:
 Define the level of price caps, network charges, and marketing charges;
 Ensure that the distributor tariff complies with the methodology; and
 Determine annually the appropriate indexation of the price caps.
CERI accepts the Consultant's views regarding the level of oversight generally required
for each methodology. However, as noted above, CERI believes that efficiency pricing
introduces an additional oversight role that is significant. This role is primarily related to
the initial information gathering and model validation that would be required to
implement efficiency pricing. It also extends to ongoing monitoring and review activities
to ensure that the methodology is leading to the desired result. The Commission should
carefully consider these issues. The following table illustrates the information
requirements of efficiency pricing as compared to cost of service regulation.
Item
COS
Historical investment in facilities
Cost allocation between customer classes
Capital structure
Cost of capital/return on equity/discount rate
AOM costs
Future market growth
Marketing/commercial costs
Market penetration rate
Future financial conditions
Detail
Yes
Yes
Yes
Yes
No
Yes
No
Short
term
Efficiency
Pricing
No
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Long term
Revenue
Cap
General
Yes
No
No
No
No
No
No
No
In the case of cost of service regulation, the level of informational detail required is likely
to be significantly greater required for efficiency prices. However, in order to establish
true efficiency prices, the Commission will be required to gather sufficient information
regarding each company to be verify that the efficiency pricing model properly represents
the specific market and circumstances of each distributor. This may in fact require that
modeling be carried out for individual municipalities or groups of municipalities, rather
than at a company level.
At this stage of analysis, the primary trade-off appears to be that efficiency prices will
require less detail regarding individual distributors' historical cost base. A more generic
representation of costs will probably be possible, although perhaps at a greater level of
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detail than currently modeled. The process of gathering the full information required and
negotiating the appropriate level of detail in the efficiency price model will take the
Commission into many of the topics familiar to cost of service regulation. On the other
hand, efficiency pricing will require long term projections of key market and financial
parameters. These projections will apply to a time period that is much longer than the
test period projections typically used in cost of service regulation. This will introduce an
element of forecast risk into distribution tariffs.
6. Conclusions and CERI Recommendations
6.1 General Issues
Natural gas distribution tariffs in Colombia must be considered in the overall context of
industry structure, market structure, market maturity, pricing regulations, and other issues
related to natural gas commercialization and massification. Although the regulations for
a competitive and open industry exist, industry and market structure create potential
impediments to a truly competitive market. The historical development of the transport
system, the method by which transport tariffs are calculated, the limited number of
suppliers, current price regulation, and the particular situation of the large thermal electric
loads are all factors that must be considered.
In addition to these current factors, distribution tariffs must be chosen to promote
objectives of gas massification and to be consistent with future trends in transmission
tariffs and wellhead pricing. Given the small number of upstream participants, wellhead
pricing will provide a particular challenge as discussed below.
6.2 City Gate Gas Costs
CERI recommends that the city-gate cost of natural gas be treated independently from
natural gas distribution tariffs. Natural gas costs should be shown as a separate item on
all end use bills, and should be based on actual purchase costs and actual volumes
delivered. This minimal level of unbundling will remove much of the difficulties
currently embodied in the tariff formula adjustment factor, and will be required as
Colombia moves to wellhead price deregulation. The simple act of unbundling gas from
distribution charges will not remove the current volatility that arises because of exchange
rate and commodity price variations. It will, however, accurately show the sources of
volatility to end customers.
In addition, as competition develops in end markets, one of the key issues will be the
prices that various competitors are able to offer. When existing customers can clearly see
the charges for gas vs. distribution, better comparisons can be made between potential
suppliers and the distributor.
The Commission should also consider mechanisms that would allow basic risk
management tools to be applied to natural gas purchases by the distributors. In this
regard, CERI's views do not align completely with the Consultant's recommendations, or
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with the current distribution tariffs. CERI believes that the natural gas distributor (or a
competing gas supplier) is in a better position to manage price risk than residential
customers. This risk management might be as simple as a deferral account, where the
distributor applies to the CREG for a commodity price each six months, based on
projections of wellhead prices, transport costs, and exchange rates. An adjustment
mechanism would be included to account for any differences between forecast and actual
rates in the previous six month period. In this simple case, the distributor would not be
permitted to earn income, but would simply pass through costs.
A more elaborate risk management scheme might allow the distributor to establish
forward positions in crude oil, or exchange rates. In this manner, the distributor would
reduce the level of risk passed through to the end customer. The distributor might even
choose to offer fixed city gate gas priced in pesos, accepting some or all of the exchange
rate and commodity risk directly. In this case, the distributor may expect compensation
for the risk assumed. Such schemes are typical of a competitive market, but would
require ongoing monitoring to alleviate any concerns of anti-competitive behavior.
6.3 Distribution Tariffs
CERI observes that the separation of industrial and residential markets for tariff purposes
appears to be required. The current adjustment formula which is based only on
residential deliveries is creating a market distortion and providing distributors with a
disincentive to discount the cost of their services to attract new industrial customers. It
also acts as an impediment to industrial gas consumption in markets where effective
competition from alternative fuels exists. Further, as Colombia moves toward a more
competitive market, the Commission will wish to encourage distributors to establish basic
customer classes for tariff purposes. Separation of residential and industrial markets is
the minimal set of customer classes within the group of regulated customers.
In addition to more efficient price signals, separate tariffs for each market segment will
help the Commission to identify and manage the level of cross-subsidization embodied in
distribution tariffs.
With regard to the tariff formula to be adopted, CERI is unable to agree completely with
the Consultant's recommendations. The mandatory option is clearly preferred to a tariff
basket formula. The latter clearly offers distributors the opportunity to price discriminate
between customer groups, basing tariffs on value of service rather than costs. This is
undesirable.
As concerns the mandatory option methodology, CERI believes that this approach could
work, although it should not be pursued without further analysis. Ongoing consultation
with the distributors will be important to the success of the mandatory option, both in
terms of achieving its efficiency objectives, and in terms of acceptance by the market. If
the mandatory option is chosen for immediate implementation, CERI recommends a
transition period in adopting efficiency prices as the mandatory option. In the interim,
the mandatory option could be based on the current distribution tariff structure. The
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transition period would then be used to validate the parameters, assumptions, projections,
and other data included in the efficiency pricing model. Further analysis would also be
required to ensure that a broad range of market conditions have been properly modeled.
Finally, the CREG should be carefully sensitive to any price shock that might be imposed
on any customers or groups of customers as a result of the transition to efficiency prices.
At a more fundamental level, CERI is not convinced that the existing tariff structures are
completely unworkable, or cannot be improved enough to merit retention. A change as
significant as adopting an entirely new methodology based on efficiency pricing should
not be considered lightly. CERI therefore recommends that the Commission consider
modifications that might be made to the existing formula to improve its usefulness. With
separate tariffs for residential and regulated industrial customers, based entirely on costs
of network services, AOM services, and commercialization costs, CERI believes that the
existing formulas could be made workable. This might be as simple as a change in
billing mechanisms to the end customer. In particular, CREG Resolution 007 of 2000
appears to provide an excellent starting point for these adjustments.
The city gate cost of gas would continue to be a source of volatility, but no distribution
tariff will be able to solve that issue. Should Colombia proceed with wellhead price
deregulation, this issue will take on greater significance. The CREG should resist the
option of replacing wellhead regulation with control over city gate gas prices. Instead,
mechanisms should be put in place to monitor city gate gas prices for evidence of anticompetitive behavior. This might include a method for end use customers to register
complaints with the CREG for subsequent investigation. Such activities should be
viewed with caution. Regulatory action should not be considered unless there is clear
evidence that the market has failed to achieve a competitive result.
6.4 Connection Charges
CERI strongly recommends that the CREG remove any possibility that connection
charges might act as an impediment to potential new customers. The simplest approach
is to allow the distributor to include the costs of new connections in its system investment
or cost base. This will reduce the cost to a new customer to those costs incurred within
the residence for internal piping or appliance conversions. Even these costs might be
considered for inclusion in investment for low income strata. In permitting distributors to
recover these costs, the Commission will need to review the level of costs, the period
over which they will be amortized, and their potential impact on network charges.
6.5 Subsidies
CERI does not consider this to be a significant issue in the current review. Existing
CREG policies appear appropriate. On the issue of competing fuel subsidies, CERI
observes that the MME may wish to undertake studies to ensure that subsidies on
competing fuels as well as natural gas are consistent with overall national energy policies.
This is an area for coordination between the CREG and the MME, but it is primarily a
matter of government policy responsibility.
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