In this section, we review the development and current state of policies in North and South America for the authorisation of new gas pipelines. These policies illustrate the way competitive contracting and at risk conditions are taken into account by the regulatory authorities, and their use in establishing future prices and terms and conditions of service.
Several different approaches have formed the basis of certification policies for new pipeline projects in the United States over the last twenty years. The historical approach employed drawn-out public hearings, in which interested parties presented evidence before an administrative law judge (ALJ) on the costs and benefits of the project under scrutiny. The ALJ would make a certification recommendation to the regulatory agency based on a weighing of this evidence.
Dissatisfaction with the ability of the regulators to make timely certification decisions led to more stream-lined approaches in the late 1980s. One approach involved the imposition of contract requirements to demonstrate sufficient market support before new capacity would be added. An alternative approach abandons the contract requirement, but requires a showing that project investors are willing to bear the full project risk and forego the opportunity to recover potential losses from regulated customers in the future. Below we describe the evolution of U.S. certification policy over time, showing how it has employed these concepts in different degrees.
U.S. certification policy for gas pipelines has traditionally been governed by Section 7(c) of the Natural Gas Act, although Section 7(c)s rather broad language has permitted an evolution of different regulations and procedures over time. Section 7(c) requires that new projects obtain a certificate of public convenience and necessity from the Federal Energy Regulatory Commission (FERC). The certificate decision is typically initially made by an administrative law judge who must consider market demand, environmental effects, economic, operational and competitive benefits of the proposed new project.
For many years, FERC held public hearings where supporters and opponents of new projects argued about these considerations in front of the administrative law judge. The FERC subsequently formalised its policy concerning the proposed demand and the economic benefits of new pipelines. The FERC imposed a rule that required all applications for new pipeline capacity to show contracts covering at least 25 percent of the proposed capacity. In addition, FERC stated that its concerns about the demand and economic benefits of a new pipeline would be allayed if an applicant showed 10-year firm contractual commitments for 100 percent of its capacity or if it showed that revenues under contracts would exceed costs. Alternatively, FERC would be satisfied if the project sponsor assumed the entire risk of losses from the project. If, however, a project could not obtain the requisite contracts, then it would have to persuade the ALJ that prospective future revenues would exceed costs.
In September of 1999, FERC issued a new policy that eliminated the previous 25 percent minimum contracting rule. The new policy requires a project sponsor (and its new customers that might commit to the project by long-term contract) to take full responsibility for the risks of under-utilised new capacity and not shift the risks to third parties such as customers on competing pipelines. Although the FERC has not specified a standard method for risk-sharing, a proposed pipeline can negotiate with its customers regarding what would happen to their respective prices if the pipeline were under-utilised. Essentially, the applicant must now either bear the entire financial risk or share the risk with its customers by negotiating in advance an agreed price.
The FERC no longer requires an applicant to present contracts for any specific percentage of the new capacity, but any signed contracts or precedent agreements for the capacity would still constitute significant evidence of demand for the project. Applicants can continue to submit precedent agreements, demand projections, potential cost savings to consumers, or other evidence supporting the financial viability of the proposed project.
In addition to evidence of financial viability, the new policy also requires an applicant to demonstrate that public benefits from the project outweigh any adverse effects. Some examples of potential benefits are: meeting unserved demand, eliminating bottlenecks, opening access to new supply sources, lower costs to consumers, providing new interconnects that improve pipeline network, providing competitive alternatives, increasing electric reliability, and advancing clean air objectives. Examples of potential negative impacts include: high environmental costs, potential excess capacity (which could affect existing pipelines and customers as well as new ones), and the potential for unnecessary exercise of eminent domain to obtain rights-of-way. To gain regulatory approval, applicants are encouraged to submit applications designed to avoid or minimise adverse effects on relevant interests including effects on existing customers of the applicant, existing pipelines serving the markets and their captive customers, and affected landowners and communities.
The elimination of the specific contract requirement also reduces the potential problems associated with lack of arm-length contracts for pipeline capacity. In the past, applicants might have used contracts with their affiliates to satisfy the contract threshold. In past years, the regulator gave equal weight to contracts between an applicant and its affiliates, and an applicant and unrelated third parties, and did not look behind the contracts to determine whether the customer commitments represented genuine growth in market. But using only contracts with affiliates to prove demand can cause problems when affiliates do not really need all of the contracted capacity. In such a case, project costs might be shifted to other customers after project construction. Under the new policy, if contracts were presented with an application, then the FERC would consider agreements with multiple non-affiliated customers to present a greater indication of market support than a project with only agreements with affiliated companies. Since the new FERC policy seeks to prevent existing customers from cross-subsidising the new projects, and to ensure that project sponsors bear all remaining financial risks, it really does not matter if the contracts are with affiliates.[4]
As a general rule, the FERC does not adopt a bright line standard of how to weigh the benefits against the costs of a particular project. Instead, it suggests that adverse impacts of a project on a particular interest could be offset by the public benefits from the project. The FERC will evaluate each case individually. Included in this evaluation could be the issue of whether the pipeline would promote competition in upstream and downstream markets.
FERCs general policy is that prices must be just and reasonable and must be made available in a non-discriminatory manner. Its new policy requires a new pipeline project to price its services incrementally and not shift its financial risks to existing customers.[5] Thus, new pipeline projects and any new customers who agree will bear the risk of under-utilised new capacity. New customers who elect to share that risk can specify (in a contract) what will happen to their prices and volumes under specific circumstances. Similarly, the risks of construction cost over-runs also should be apportioned between the pipeline and its new customers in their service contracts. Basically, existing customers should not subsidise new entrants and should not bear the cost of unused capacity that results from a competing project that might be not financially viable after the fact.[6] The FERC takes the view that incremental pricing sends the correct price signals for new entry and provides incentives for efficient project sizing and timing.
In evaluating pipeline projects, the FERC will consider the amount of public benefits compared to any adverse effects of a proposed project. Specifically, it will consider the interests of applicants existing customers, competing pipelines and their captive customers, and the interests of landowners and surrounding communities. In the past, the FERC did not deny applications on the grounds of the possible economic impact of a proposed project on existing pipelines serving the same market or on the existing pipelines customers. With the new policy, their interests will be taken explicitly into consideration.
Under FERCs new policy, the amount of evidence necessary to establish market support for a proposed pipeline project will depend on the potential adverse effects of the project on the relevant interests mentioned above. Thus, projects that would serve new demand might not need to show as many public benefits as those that supply markets served by existing pipelines.[7] Thus, if the applicant is willing to bear the entire risk of the project, and not cause potential harm to third parties, then the FERCs certification requirements are not very stringent.
If an applicant would cause adverse impacts on customers of another pipeline, then the applicant must show evidence of strong benefits to consumers, such as lower rates for the customers to be served. The FERC may also consider how the proposal would affect the cost recovery of the existing pipeline, particularly the amount of unsubscribed capacity that would be created and who would bear the costs associated with this stranding. In such cases, the FERC would require evidence of benefits to be more specific and detailed than the generalised benefits of increasing competitive alternatives. While the policy does not focus on protecting incumbent pipelines from the risk of losing market share to a new entrant, it simply takes that impact into consideration when evaluating the project for certification. Although the captive customers of existing pipelines can be asked to pay for the unsubscribed capacity under the current pricing scheme for gas pipelines, the FERC indicates that it would not permit all costs resulting from the loss of market share to be shifted to captive customers.
In evaluating new pipeline projects or expansion projects, the FERC follows two steps. First, it attempts to evaluate whether the project can proceed without subsidies from existing customers. This usually means that the project would be incrementally priced if it were an expansion of an existing pipeline. Second, the FERC determines whether the applicant has made efforts to eliminate or minimise any adverse effects the project might have on the existing customers of the pipeline proposing the project, existing pipelines in the market and their captive customers, or landowners and communities affected by the route of the new pipeline. Accordingly, the FERC evaluates the efforts made by the applicant and assists the applicant in finding ways to mitigate the effects.
Because this policy is relatively new, few guidelines or case precedent are available for the quantifying of these costs and benefits. Indeed, in one very recent case decided on 26 April 2000, the FERC elected not to employ its new, September 1999 policy to three competing pipeline proposals to serve the Northeast U.S. from the Midwest. Instead, it approved but deferred granting final certificates for all three projects until two of them filed long-term, executed contracts with nonaffiliated shippers for at least 35% of their respective project capacity. In so doing the FERC rejected the contracts with affiliated companies that the project sponsors had previously used in an attempt to justify the market demand for the capacity.[8]
Generally speaking, FERCs policies toward new pipeline certification have had the virtue that substantial information about competing pipeline projects is made available to the public. This has had the beneficial effect of making it easier for prospective subscribers to new capacity to compare the relative economic merits of the competing proposals. In the case of the requirement to show contracts, the FERCs policy has been to make those contracts available to the public at the time they are filed unless serious confidentiality concerns are established by the project sponsor.
New pipeline projects in Canada must obtain a certificate of public convenience and necessity from the National Energy Board (NEB). The NEB would assess and issue certificates based on each projects environmental impact, economic feasibility, potential commercial impact, socio-economic and land issues, engineering and safety matters, tariffs, and the form of regulation.[9] Public hearings are allowed for all certification applications, and the NEB considers the objections of any interested person that it considers relevant.
Typically, the NEB has required a showing of firm commitments on new pipelines before approving the projects. This process is used to ensure that new pipelines and their customers are responsible for the financial and economic viability of the new pipelines. Pipeline sponsors can negotiate prices with their customers but the settled prices would be based on the costs of providing the services and must be put on record with NEB. Regarding the risks of under-utilisation on existing pipelines caused by the new projects, the NEB has made existing pipelines and their captive customers responsible for any lost revenues associated with under-utilised facilities. This means that the captive customers would pay for at least a portion of the costs of under-utilised pipelines. In response to the changing dynamics in the North American gas market, the largest pipeline in Canada, TransCanada, recently requested NEB approval of greater pricing flexibility for its interruptible and short-term firm transmission services.[10]
Recently, for example, a new pipeline requested (and received) regulatory approval of a pricing scheme referred to as Authorised Overrun Service (AOS). Under AOS, the pipeline would allocate all of the spare capacity (which varies over time) to firm service shippers according to each shippers contracted firm service volumes.[11] There would be no charge for moving gas under this service other than the fuel charge. The pipeline submitted that this service would put the control of the available capacity in the hands of the shippers. This service also would allow the pipeline to allocate all of the pipelines fixed costs to firm service shippers and only market interruptible service when capacity is not used up in the AOS. Since the firm service shippers would be paying for all of the fixed costs of the pipeline through their demand charge payments, they essentially have the first right of refusal for all of the pipelines capacity. The transportation rights for AOS would be tradable on a secondary market and thereby provide additional flexibility to the shippers.[12]
Here, we will focus on Canadian new pipeline authorisation procedures, and when they rely on market-based decisions as opposed to detailed regulatory scrutiny of new pipeline projects.
Under the economic feasibility assessment, the NEB reviews the availability of gas, the existence of markets (actual or potential), the economic viability of the pipeline, the financial responsibility and financial structure of the project sponsors, and any public interest that may be affected by the application.
The NEB is required by Canadian law to evaluate the availability of gas supply to a proposed gas pipeline project. This requirement does not mean that the NEB must be assured that there will be adequate gas supplies to keep a pipeline project full at all times. Rather, the NEB must be satisfied that there is a reasonable expectation that adequate supplies of natural gas will be available so that the facilities can be justified over the economic life of the project. Although the NEB does not necessarily rely on shippers to contract long-term sources of supply at the outset of the proposed project, it does consider shipper commitments to long-term transportation contracts as strong evidence that an adequate supply will be available to the pipeline project. If the applicant makes a credible case that the overall supply will be sufficient, on a long-term basis, to sustain a reasonable utilisation rate on the proposed pipeline and on other pipelines that transport gas from the same region, then the NEB deems the gas supply adequacy standard to have been fulfilled.
The applicant needs to perform a market analysis to convince the NEB that customer demand will be sufficient to support the project. The applicant typically submits a market demand forecast that shows the market potential both in the near-term and in the longer-term (of 15 to 20 years) either by using analysis from regulatory agencies or from another unbiased third party. Several applicants have stated in their applications that they and their shippers would take the financial risks with respect to any unutilised capacity on their pipelines. However, under the current pricing design, costs associated with the displacement of capacity on an existing pipeline is typically not the responsibility of a new pipeline.[13]
For economic viability or feasibility, the NEB recognises that with a pipeline addition, the overall available capacity may exceed the ability or willingness of producers to supply gas at the prevailing market prices for some time immediately after the new pipeline is constructed. However, the NEB still considers a project economically feasible if the shippers support the project by signing long-term contracts for a significant portion of the new pipeline. On a case-by-case basis, the NEB may require an applicant to identify shippers that have made contractual commitments and to make the details of their commitments available to the public.
For project financing information, the applicant should provide a proposed capital structure for the project and demonstrate to the NEB its ability to secure financing. When shippers make long-term commitments by signing transportation contracts, the NEB assumes that the shippers have decided that these commitments constitute the best use of their available capital. The NEB regards these commitments as sufficient evidence of financial support for the project.
For the commercial impact assessment, the applicant needs to provide evidence to the NEB of the new projects potential impacts on third parties. The potential beneficial impacts could be the increased choice and competitive benefits to parties other than the shippers on the proposed pipeline. A potentially negative impact could be the stranding of capacity on existing pipelines that could create financial hardship for their shareholders and/or their customers. The NEB then examines how the proposed project would impact overall competition in the gas market and more specifically how it might impact the netback prices received by gas producers.[14] We summarise here Canadian evaluation procedures for market competition and impacts on existing pipelines.
NEB certification decisions apparently do not depend on quantification of competitive benefits from applicants. Instead, the NEB believes that if producers and (regulated) local distribution companies support a project, then they are demonstrating their desire for choice and competition. The NEB would conclude that a project well-supported by producers and local distribution companies must bring long-term value to the Canadian gas industry.
The rate structure for gas pipelines in Canada allows pipeline companies to recover from their customers those costs associated with lower utilisation of existing pipelines as a result of construction of new pipelines. The NEB believes that the potential for duplication of facilities is inherent in the nature of competition; if commercial negotiations do not completely eliminate potential duplication, then it will likely be due to the parties judgement that they are willing to compete in certain areas. The NEB views that duplication that results in beneficial competition may be considered to be in the public interest. The NEB has not, so far, held applicants responsible for the potential of stranding competing pipelines assets, although any party so harmed is free to bring such a case requesting relief.
As in the U.S., Canadian authorities require that all prices charged by natural gas pipelines be just and reasonable and that the associated services must be made available in a non-discriminatory manner. Under its guidelines, the NEB allows pipelines and their shippers or customers to negotiate prices. The NEB considers the negotiated settlement process as a means for pipeline companies and interested parties to resolve issues and agree on tolls and tariffs without resorting to a public hearing process.[15] However, the negotiated prices are not the same as market-based prices. They are, rather, prices based on the cost of service. For all negotiated prices, the pipeline company must provide the NEB with a tabulation of the agreed revenue requirements, the resulting tolls, an explanation of how the tolls were derived, and a description of issues that might have arisen and their resolution.[16]
For capacity expansion projects, the costs of new expansions can be averaged in with existing costs such that prices are set based on the overall costs of the system. And for new pipelines, applicants must show enough demand and plan to recover all costs from its customers.
The NEB has not set specific rules prohibiting the use of contracts with affiliates to demonstrate market support for a project. However, it requires the applicant to offer to all shippers the same opportunity to participate, and enter into contracts under the same terms and conditions of service, as it does affiliates.[17]
The construction of new pipelines in Colombia does not require government authorisation. However, pipelines must apply to the Commission for the approval of regulated rates. Pipelines are allowed to negotiate prices with customers, but only against the background of a regulated recourse rate determined by the Commission. The rate-making process involves a careful analysis of forecast volumes. Incentives for efficient utilisation of the pipeline are embedded in the rate design and are expected to deter inefficient investments.
The rate design methodology is a price-cap equal to the forward-looking long run average cost (LRAC). The LRAC ($/Btu) is defined as the ratio of the discounted value of capital costs plus efficient operating and maintenance costs to the discounted value of total volume forecasts. The forecasts have to be properly justified according to macroeconomic forecasts, power plant dispatch and other relevant factors. A minimum fill rate is imposed whenever volume forecasts are considered too low when compared to maximum capacity. Once the regulated rates have been set, the pipeline owners retain the rights to any additional profit as a result of higher than forecasted gas flows.
Two recourse services are required at regulated rates. A one-year service must be available for gas distribution companies and large industrial users, which allocates 75% of costs to a fixed charge and 25% to a variable charge. A five-year service is available for power plants, which allocates 50% of costs to a fixed charge and 50% to a variable charge. However, customers are free to negotiate different rate structures and services if they wish.
A first example of the application of these regulations is the case of GasOriente pipeline. The actual volumes were far less than forecast, because of the unexpected cancellation of a gas-fired power plant project. The pipeline owner petitioned the Commission to re-compute charges using lower volume forecasts, which would allow the pipeline to raise the rates for other existing customers. However, the petition was denied by the Commission.
Electricity transmission projects are similar to gas pipeline projects, as they can both involve substantial, fixed investments and potentially complex relationships with existing networks. In Argentina, the regulatory Commission automatically allows small-scale transmission projects that are financed by private contracts with third parties. However, quite a complicated approval mechanism is used for large-scale projects.
For large-scale investments, a group of interested parties must file an application outlining the details of the project, including the proposed charges for building, operation, and maintenance (BOM). The government must evaluate the proposal and verify that it will benefit the national transmission system by lowering the net present value of investment, operation and maintenance costs. Next, the operator of the electricity transmission system identifies the set of customers whose average electricity flows may change substantially as a result of the new project. If the project is approved, its costs will be allocated to these customers. These customers have the right to veto the project in a vote, if at least 30% support cancellation.
If customers do not veto the project, then the regulator conducts a public tender to determine whether any third party will build, operate and maintain the same project for lower costs than expressed in the initial proposal.
In February 1995, a proposal was made to construct a 1,000 MW transmission line between Comahue and Buenos Aires at a cost of US$200 million. The main beneficiaries were seven generators from the Comahue region suffering from reduced generation load and low local prices because of transmission constraints. However, the potential beneficiaries of the project vetoed it because they could not agree on the allocation of costs. After some negotiations between beneficiaries, the project was reformulated and filed anew. The project was then approved.